Methods and apparatus for storage and recovery of hydrocarbon fluids

ABSTRACT

A hydrocarbon strategic reserve method comprises operating production wells deployed in a post-pyrolysis oil shale formation at significantly elevated wellhead pressures for an extended period of time so as to store hot hydrocarbon fluids within pore space thereof. In some embodiments, the hydrocarbon fluids are stored at a depth of at least 100 meters or at least 200 meters or at least 300 meters. In some embodiments, the hydrocarbon fluids are stored substantially at or above bubble point curve thereof.

BACKGROUND AND RELATED ART Strategic Petroleum Reserves

In 1975, the United States government created the Strategic Petroleum Reserve, after oil supplies were cut off during the 1973-74 oil embargo. Strategic reserves are useful not only as insurance against supply disruptions but also to buy and store oil when prices are low and to release oil to refiners when there is a spike in global rates. The price paid for oil in the strategic reserve, $29.76 per barrel, is significantly less than the current spot price for crude.

Emergency releases of over 20 million barrels of crude after Hurricane Katrina were useful for maintaining supply in the wake of that natural disaster. In January, 2009, with spot oil prices significantly below their record 2008 highs, contracts to completely fill the US strategic reserve to 727 million barrels were signed.

The 1973-1974 oil embargo was, unfortunately, not an isolated event. Ongoing risks to world-wide or local supply remain Hurricanes or earthquakes may damage infrastructure (for example, ports, pipelines or offshore rigs) for importing or producing oil or other petroleum fluids. Political volatility may also increase the likelihood of a severe local shortage, especially in remote locations or in countries that rely exclusively on overseas suppliers or on a single supplier. Regime change or risks thereof in a oil-producing or a gas-producing nation, or in a nation that controls supply routes, may also adversely affect price and availability or hydrocarbon fluids (e.g. oil or natural gas).

Many industrialized countries have recognized the value of strategic petroleum reserves for ensuring that the needs of the civilian population and of the armed forces needs are met during periods of limited supply. Countries which have a strategic petroleum reserve, or which are planning such reserves, include the United States, the United Kingdom, France, Israel, Germany, Italy, South Africa, China, Japan, India, South Korea, and many more. The size of the strategic reserves varies between countries.

According to a March 2001 agreement, all 28 members of the International Energy Agency must have a strategic petroleum reserve equal to 90 days of prior year's net oil imports for their respective country. European Union Council Directive 68/414/EEC of 20 Dec. 1968 similarly mandates that each country store a 90 day supply. According to Wikipedia, Korea maintains a 34-day supply in their strategy reserve, Israel a 270-day supply, Taiwan a 30-day supply, and Jordan a 60-day supply.

The United States has the largest reported Strategic Petroleum Reserve SPR) with a total capacity of 727,000,000 barrels (115,600,000 m³). If completely filled, the US SPR could theoretically replace about 60 days of oil imports as the US is estimated to import approximately 12,000,000 barrels per day (1,900,000 m³/d) of crude oil.

For a strategic reserve, oil can also be stored above ground in tanks or underground. The United States strategic reserve is distributed among a number of underground salt caverns located in Louisiana and Texas.

Volume 3, Issue 2 of Tank Storage magazine notes, in an article entitled “UNDERGROUND STORAGE—THE UNDERSTUDY” that underground storage brings “added social and environmental benefits” when compared with above-ground storage. According to the article, “Canada opened its first underground crude storage cavern in 2003. Caverns storing crude are also to be found in locations including Japan, Korea, Norway, Sweden, France, Zimbabwe and South Africa, and cavern storage projects for strategic reserves are also believed to be underway in India.”

Underground facilities are useful in countries where land is at a premium. Furthermore, underground facilities are less vulnerable to attacks by belligerent governments or organizations.

Underground salt caverns are considered safe for storing hydrocarbons due to the lack of porosity in the surrounding salt formations. These caverns are created by drilling a conventional well to pump fresh water into a salt dome or bedded salt formation. The salt dissolves until the water is saturated, and the resulting salt water is returned to the surface. This process continues until a cavern of the desired volume and shape is created.

The present disclosure relates to techniques and apparatus for underground storage of hydrocarbon fluids.

SUMMARY OF EMBODIMENTS

The present disclosure relates to techniques and apparatus for underground storage and recovery of hydrocarbon fluids. Instead of relying on underground caverns for subsurface storage, it is possible to store hot, pressurized hydrocarbon fluids, for an extended period of time (e.g. for at least several months or at least several years) within pore space of a previously-pyrolyzed oil shale formation—for example, at a depth at least 100 meters, or greater. In some embodiments, the hot hydrocarbon fluids are stored, as a liquid, at or above a bubble point curve thereof for an extended period of time.

In response to any ‘demand triggering event’ (e.g. a supply shock or natural disaster or an interruption in domestic petroleum production or an outbreak of hostilities), the pre-stored hot hydrocarbon fluids may be recovered by reducing pressure in the production wells within the oil shale formation. In embodiments where the hot hydrocarbon fluids are stored at or above a bubble point curve thereof for an extended period of time, reduction of the production well pressure may cause at least some of the hydrocarbon fluids to flash into a gas. By storing hydrocarbon fluids in the liquid-phase and producing them in the gas phase, it is possible to benefit both from (i) the relatively high storage efficiency of liquids (i.e. because liquids are much denser than gases) and (ii) relatively fast recovery of the stored hydrocarbon fluids (i.e. because gases tend to be less viscous than liquids, they encounter less flow resistance).

Examples of hydrocarbon fluids that may be stored within the pore space of the previously-pyrolyzed oil shale formation include pyrolysis fluids, and stabilized unhydrotreated synthetic condensates (SUSC) derivatives of pyrolysis fluids.

A first embodiment relates to in situ storage of hydrocarbon pyrolysis formation fluids within pore space of the formation. During and subsequent to pyrolysis of the formation, a wellhead pressure of production wells within the oil shale formation may be maintained at an elevated level (e.g. at least 20 or least 30 or at least 40 or at least 50 or at least 60 atmospheres). By maintaining the production wells at these elevated pressures for an extended period of time, it is possible to delay recovery of significant quantities of hydrocarbon pyrolysis formation fluids so as to maintain and store these fluids within pore space of the oil shale formation for significant periods of time.

In order to reduce the incidence of steam stripping of stored C7+ hydrocarbon pyrolysis fluids within pore space of the post-pyrolysis formation, it is possible to employ a dual phase-production well so as to recover aqueous products of pyrolysis in the liquid phase. For example, it is possible to pump liquid brine comprising the aqueous pyrolysis products through a production tubular section of a dual phase production well, with the pump located in a cold rathole section below the heated zone.

The first embodiment discussed above relates to in situ storage of hydrocarbon pyrolysis formation fluids within pore space of the formation. In a second embodiment, it is possible to (i) recover hydrocarbon fluids from a first oil shale target region; (ii) process the recovered hydrocarbon fluids (e.g. substantially at the surface) so as to form a SUSC therefrom; (iii) introduce the SUSC into a second oil shale target region that is previously-pyrolyzed, hot and non-communicating with the first oil shale target region; (iv) store the introduced oil within pore space of the second oil shale target. After a significant amount of time (e.g. in response to the demand-triggering event), it is possible to recover the stabilized and/or pipelinable (i.e. at standard operating conditions) SUSC from the second oil shale target.

During the storage phase of the second embodiment, in order to store the previously-sweetened stabilized oil within pore space of the second oil shale target region, it may be necessary to sustain (i.e. for a significant amount of time) a significantly-elevated wellhead pressure of production wells deployed within the second oil shale target region. For example, even though the oil stored within the second oil shale target region is hot, the wellhead pressure may be maintained so as to store the oil substantially at or above a bubble point curve of the oil. During recovery, reduction of wellhead pressure may cause some or all of the stored oil to flash into a gas for rapid recovery.

The first embodiment discussed above relates to in situ storage of hot, pressurized hydrocarbon pyrolysis fluids within pore space of a previously-pyrolyzed oil shale formation. The second embodiment discussed above relates to in situ storage of hot, pressurized stabilized oil within pore space of a previously-pyrolyzed oil shale formation.

During the storage phase of the second embodiment, in order to store the stabilized oil within pore space of the second oil shale target region, it may necessary to sustain (i.e. for a significant amount of time) a significantly-elevated wellhead pressure of production wells deployed within the second oil shale target region. For example, even though the oil stored within the second oil shale target region is hot, the wellhead pressure may be maintained so as to store the oil substantially at or above a bubble point curve of the oil. During recovery, reduction of wellhead pressure may cause some or all of the stored oil to flash into a gas for rapid recovery.

For all three embodiments, in order to delay recovery so as to store the hot (i.e. at least 150 degrees Celsius) hydrocarbon fluids within the target portion, it may be necessary to sustain wellhead pressures of at least 20 atmospheres during pyrolysis and during storage. By operating target production wells (i.e. those configured to receive pyrolysis fluids from the target portion) at a relatively high pressure, it may be possible to stably store, within the pore space, significant quantities of C6+(or C7+) hot pyrolysis fluids or any component thereof as a liquid rather than as a gas, thereby increasing the hydrocarbon storage density by an order of magnitude or more.

Some embodiments relate to a multi-stage method including (i) dewatering, (ii) pyrolysis and (iii) storage stages. During the dewatering stage, in situ heaters heat the target portion so as to vaporize water therein. The water vapor is removed via target production wells that operate at a relatively low wellhead pressure so as allow relatively unrestricted recovery of H₂O out of the oil shale formation. Subsequent to the dewatering phase, in situ heaters continue to heat the target portion until a pyrolysis temperature is reached.

While at pyrolysis temperatures (i.e. during the pyrolysis stage), kerogen within the target portion is transformed into pyrolysis fluids. During or before the pyrolysis stage, the wellhead pressures of the target production wells are significantly increased and maintained at 20 atmospheres or more throughout substantially the entire pyrolysis phase.

Upon substantial completion of the pyrolysis reactions within the target portion, a storage stage commences. The elevated wellhead pressures of at least 20 atmospheres are sustained throughout substantial entireties of both the pyrolysis and storage stages. By maintaining the wellheads at elevated pressures, it is possible to (i) retain C6+ pyrolysis fluids within the pore space of the target portion (e.g. at a depth of at least 100 meters, or deeper) so that these fluids are stored underground rather than immediately recovered via production wells; and (ii) maintain significant quantities of C6+ pyrolysis fluids stored in the subsurface pore space as a liquid and/or as a supercritical fluid.

In some embodiments, during the storage stage, a hydrocarbon strategic reserve formed by in situ pyrolysis of an oil shale formation comprises: C6+ pyrolysis fluids stored, at a storage temperature of at least 250 degrees Celsius and at wellhead pressures of at least 20 atmospheres, in pore space of a target portion of an oil shale formation having a minimum depth of at least 100 meters, a majority of the stored C6+ pyrolysis fluids within the target portion stably existing as a liquid or supercritical fluid. In some embodiments, C6+ pyrolysis fluids are stored (e.g. for an extended period of time) within pore space throughout a substantial entirety of the target portion—for example, a target portion having length, width and height of at least 50 meters, or at least 100 meters, or at least 150 meters.

At a later time, after storing the pyrolysis fluids within the pore space of the target region, it is possible to recover these fluids via production wells. For example, in response to any ‘demand triggering event’ (e.g. a supply shock or natural disaster or an interruption in domestic petroleum production or an outbreak of hostilities), the pressure in the production wells may be significantly reduced so that some liquid-phase C6+ or C7+ pyrolysis fluids flash into the gas phase proximate to the production wells or in the target portion of the subsurface. C6+ pyrolysis fluids may be recovered by gas-phase flow, or by multiphase flow of the C6+ pyrolysis fluids through the production wells.

The combination of liquid-phase storage (or storage of supercritical fluids) followed by at least partial gas-phase recovery provides (i) a storage-density advantage of liquid phase storage where a relatively large mass of hydrocarbon fluids may be stored in a relatively small volume of the subsurface formation for any period of time and (ii) the producibility advantage of gas-phase recovery where a gas or a gas-liquid mixture flows through the pyrolyzed formation towards the production wells and is recovered within the production wells with significantly less flow resistance than would be encountered by liquids (i.e. which have a significantly higher viscosity than gases).

Not only may C6+ pyrolysis fluids flow, relatively unhindered, within the production wells towards the wellheads, but C6+ pyrolysis fluids may exhibit relatively high mobility within the target portion of the shale oil formation, as they flow towards the production wells. More specifically, even in locations away from the production wells where C6+ pyrolysis fluids may be observed primarily in the liquid phase as they flow towards the production wells, the viscosity of the liquid C6+ or C7+ pyrolysis fluids is quite low at elevated temperatures—e.g. at most 5 centipoise (cP) or at most 2 cP or at most 1 cP or at most 0.5 cP.

Although the presently-disclosed techniques may be employed in any oil shale formation, kerogenous chalks are preferred due to their high porosity, and potentially high kerogen content. Although not a requirement, a thick oil shale formation having a thickness of at least 100 meters is preferred. The combination of a thick formation and a high porosity increases the storage efficiency, thereby storing more hydrocarbons in a target volume and reducing a number of production wells required. In different embodiments, a post-pyrolysis porosity of at least 30%, or at least 35%, at least 40%, at least 45%, or at least 50% may be observed within the target portion of the oil shale formation.

Not only does the oil shale formation provide storage space without any need to form a subsurface cavern, but the oil shale formation (i.e. after in situ heating therein) provides features conducive to containment of hydrocarbon fluids within the target portion. For example, (i) an absolute permeability of the surrounding or adjacent zone may be extremely low (e.g. less than 0.2 mD or less than 0.1 mD) and significantly less than that of the target portion; and (ii) in contrast to the target portion where substantially all water is vaporized in situ, the surrounding or adjacent zone remains fully water saturated. As such, the effective permeability of hydrocarbon fluids within the surrounding or adjacent zone of the oil shale formation is even lower.

This extremely low effective permeability of hydrocarbon fluids within the surrounding or adjacent zone restricts migration of hydrocarbon fluids thereto from the target portion of the oil shale formation, so as to substantially contain the hydrocarbon fluids within the target portion.

It is believed that pyrolysis of the target portion of the formation significantly increases the permeability thereof both in absolute terms and relative to the unpyrolyzed surrounding or adjacent zone. Although the permeability within the previously-pyrolyzed target portion is not particularly high (e.g. at least 0.4 mD), substantially all water is vaporized therefrom in situ so that the effective permeability of the C6+ or C7+ hydrocarbon pyrolysis fluids stored therein equals the absolute permeability. Furthermore, it is believed that the viscosity of the hot liquid-phase C6+ hydrocarbon pyrolysis fluids stored therein is sufficiently low (e.g. a viscosity of at most 5 centipoise (cP)) to allow for reasonable flow rates within the target region—for example, in the event that hydrocarbon fluids are required quickly.

The examples above relate to creating a strategic reserve of hydrocarbon fluids derived from kerogen of the oil shale formation. Alternatively or additionally, it is possible to introduce hydrocarbon fluids into the subsurface formation post-pyrolysis and to store the externally-introduced hydrocarbon fluids therein. These externally introduced hydrocarbon fluids may be introduced from the surface into the subsurface formation, for example, via production well(s) or injection well(s) or in any other manner.

In one example, pyrolysis fluids and externally-introduced hydrocarbon fluids may ‘co-reside’ in pore space of the oil shale formation so that the strategic reserve comprises both pyrolysis fluids produced within the subsurface formation as well as externally-introduced hydrocarbons. This may allow storage of an even greater quantity of hydrocarbon fluids in a region of the subsurface formation, and to take further advantage of the pore space storage capacity of the target region, which may have a porosities exceeding 40% or exceeding 45% or exceeding 50%.

Examples of externally-introduced hydrocarbons include but are not limited to crude oil, natural gas or LPG. In one non-limiting example, it is possible to store natural gases extracted from potentially ‘vulnerable’ off-shore gas rigs that are prone to hurricanes or attacks from a belligerent country or organization. Because the main component of natural gas, methane is resistant to thermal cracking, it may be particularly useful to store methane in heated or unheated subsurface porous formations.

It is now disclosed a hydrocarbon strategic reserve method comprising: operating production wells deployed in a post-pyrolysis oil shale formation at significantly elevated wellhead pressures for an extended period of time so as to store hot hydrocarbon fluids within pore space thereof, the hydrocarbon fluids being stored (i) at a depth of at least 100 meters or at least 200 meters or at least 300 meters and/or (ii) substantially at or above bubble point curve of the hydrocarbon fluids.

In some embodiments, the stored hydrocarbon fluids include and/or are primarily unhydrotreated fluids.

In some embodiments, the stored hydrocarbon fluids are primarily C7+ hydrocarbon fluids.

In some embodiments, the stored hydrocarbon fluids are primarily native C7+ pyrolysis fluids derived from the oil shale formation and stored in situ therein.

In some embodiments, the stored hydrocarbon fluids comprise a stabilized unhydrotreated synthetic condensate (SUCS) derived from pyrolysis fluids.

In some embodiments, the stored hydrocarbon fluids include external hydrocarbon fluids (e.g. natural gas) that are injected into pore space of the post-pyrolysis oil shale formation after pyrolysis thereof.

In some embodiments, the stored hydrocarbon fluids are native C7+ pyrolysis fluids derived from the oil shale formation and stored in situ therein, wherein the production wells are dual phase production wells, and wherein the method further comprises: upon pyroylsis of the oil shale formation, operating the production wells therein at the significantly elevated wellhead pressure so that primarily aqueous pyrolysis liquids are recovered by pumping through production tubulars of the production wells while pyrolysis gases are recovered via an annular section of the production wells.

In some embodiments, the production wells are operated for the extended period of time at a governing wellhead pressure of at least 20 atmospheres, or at least 30 atmospheres, or at least 40 atmospheres, or at least 50 atmospheres, or at least 60 atmospheres.

In some embodiments, the hot hydrocarbon fluids are stored at a depth of at least 100 meters, or at least 300 meters, or at least 350 meters, or at least 400 meters.

In some embodiments, the hot hydrocarbon fluids are stored for the extended period of time comprise primarily C7+ hydrocarbon fluids, or primarily C8+ hydrocarbon fluids.

In some embodiments, the hot hydrocarbon fluids are stored for the extended period of time substantially at or above bubble point curve thereof.

In some embodiments, a temperature of the hot hydrocarbon fluids is at least 160 degrees, or at least 180 degrees, or at least 200 degrees, or at least 250 degrees, or at least 275 degrees, or at least 300 degrees.

In some embodiments, the target portion has a length, width, and height of at least 100 meters.

In some embodiments, the hot hydrocarbon fluids are stored for the extended period of time substantially throughout an entirety of the target portion.

It is now disclosed a method of creating a hydrocarbon strategic reserve of hydrocarbon fluids within an oil shale formation, the method comprising: operating the subsurface heaters so to pyrolyze, by an in situ thermal process, a significant portion of the oil shale formation; and operating the production wells so as to recover, in the liquid phase, a majority of the aqueous pyrolysis formation fluids of the significant portion of the oil shale formation while substantially all of the C7+ pyrolysis formation fluids of the pyrolyzed significant portion remain in the pore space thereof.

In some embodiments, the majority of the aqueous pyrolysis formation fluids of the significant portion of the oil shale formation are recovered by pumping.

In some embodiments, the majority of the aqueous pyrolysis formation fluids of the significant portion of the oil shale formation are recovered by pumping through a production tubular of a dual-phase production well.

In some embodiments, a downhole separator is maintained at or near the production well.

In some embodiments, a cold sump is maintained at or near the production well. It is now disclosed a method of creating and maintaining a hydrocarbon strategic reserve, the method comprising: a. during a pyrolysis phase, operating subsurface heaters so as to pyrolyze, by an in situ thermal process, a target portion of an oil shale formation having a depth of at least 100 meters or at least 200 meters or at least 300 meters, thereby converting organic matter therein into hot pyrolysis fluids; and b. during a storage phase and after a majority of the organic matter has been converted into hot pyrolysis fluids, storing a majority of the hot pyrolysis fluids within the pore space of the target portion for an extended period of time, wherein during substantial entireties of each of the pyrolysis and storage phases, the target portion is maintained at a wellhead pressure of at least 20 atmospheres, or at least 30 atmospheres, or at least 40 atmospheres, or at least 50 atmospheres, or at least 60 atmospheres.

It is now disclosed a method of creating and maintaining a hydrocarbon strategic reserve within an oil shale formation, the method comprising: a. pyrolyzing organic matter of a first oil shale target region into pyrolysis fluids b. producing the pyrolysis fluids via multi-phase production wells; c. forming a stabilized unhydrotreated synthetic condensate (SUSC) from the produced pyrolysis fluids by separating therefrom (i) water, (ii) light hydrocarbon fractions and (iii) light sulfur-containing molecules; d. introducing the hydrocarbon fluid comprising or derived from the SUSC into a second oil shale target region that is hot, previously pyrolyzed and non-communicating with the first oil shale target region so that the introduced hydrocarbon fluid resides within pore space of the second oil shale target region; and e. operating production wells within the second oil shale target region at an elevated pressure so as to store the introduced hydrocarbon fluid for an extended period of time as a hot fluid and substantially at or above its bubble point curve.

In some embodiments, i. the storing commences concurrent with or immediately upon completion of the pyrolyzing; ii. during substantial entireties of the pyrolyzing and the storing, a wellhead pressure of the target region is maintained (i) at or above 20 atmospheres; or (i) at or above 30 atmospheres; or (i) at or above 40 atmospheres; or (i) at or above 50 atmospheres; or (i) at or above 60 atmospheres.

In some embodiments, the wellhead pressure is maintained (i) at or above 30 atmospheres during substantial entireties of the pyrolyzing and the storing; or (ii) at or above 40 atmospheres during substantial entireties of the pyrolyzing and the storing; or (iii) at or above 50 atmospheres during substantial entireties of the pyrolyzing and the storing; or (iv) at or above 60 atmospheres during substantial entireties of the pyrolyzing and the storing.

In some embodiments, a depth of the target portion is at least 200 meters or at least 300 meters, or at least 350 meters, or at least 400 meters.

In some embodiments, a molar majority of the hot hydrocarbon pyrolysis fluids stored for the extended period of time are C7+ pyrolysis fluids.

In some embodiments, a temperature of the extended-period-stored hot hydrocarbon pyrolysis fluids equals or exceeds 250 degrees Celsius.

In some embodiments, a significant fraction of the organic matter of the target portion is pyrolyzed into the hydrocarbon pyrolysis fluids which are stored within the target portion for the extended period of time.

In some embodiments, a majority, by mass, of the organic matter of the target portion is pyrolyzed into the hydrocarbon pyrolysis fluids which are stored within the target portion for extended period of time.

In some embodiments, the target portion has a length, width, and height of at least 50 meters, or at least 100 meters.

In some embodiments, the formed hydrocarbon pyrolysis fluids are stored for the extended period of time substantially throughout an entirety of the target portion. In some embodiments, a majority of the stored hydrocarbon pyrolysis fluids remain within the target portion at the depth of at least 250 meters during entireties of the pyrolyzing, the storing and in the interim.

In some embodiments, substantially all of the stored hydrocarbon pyrolysis fluids remain within the target portion at the depth of at least 250 meters during entireties of the pyrolyzing, the storing and in the interim.

It is now disclosed a method of creating and maintaining a hydrocarbon strategic reserve within an oil shale formation, the method comprising: a. pyrolyzing organic matter of first oil shale target region into pyrolysis fluids comprising steam and vapor-phase hydrocarbons; b. producing the pyrolysis fluids via production wells; c. cooling and separating the pyrolysis fluids into hydrocarbon and aqueous condensates; and d. introducing a hydrocarbon fluid comprising the hydrocarbon condensate or a hydrocarbon derivative thereof into a hot second oil shale target region that is pre-pyrolyzed and significantly horizontally displaced from the first oil shale target region so that the introduced hydrocarbon fluid resides within pore space of the second oil shale target region at a depth of at least 100 meters or at least 200 meters or at least 300 meters.

In some embodiments, the introduced hydrocarbon fluid is heated by latent heat of the pre-pyrolyzed second oil shale target region to at least 250 degrees.

In some embodiments, further comprising storing the introduced hydrocarbon fluid within pore space of the second oil shale target region at the depth of at least 250 meters for an extended period of time.

In some embodiments, the introduced hydrocarbon fluid is heated by latent heat of the pre-pyrolyzed second oil shale target region to at least 250 degrees.

In some embodiments, the introduced hydrocarbon fluids is stored for the extended period of time in the pore space of the second oil shale target region substantially at or above bubble point curve conditions.

In some embodiments, during storage, the hot hydrocarbon fluids within the pore space of the post-pyrolysis formation, have a viscosity of at most 1 cP, or at most 0.5 cP.

In some embodiments, a length, width and height of the target portion is at least 50 meters, and the hot hydrocarbon fluids are stored throughout substantially an entirety of the target portion.

In some embodiments, during substantially an entirety of the storage phase, throughout substantially an entirety of the target portion, the hot C7+ pyrolysis fluids are stably stored primarily as a liquid.

In some embodiments, after pyrolysis the target portion has a pyrolyzed porosity of at least 30%, or at least 40% or at least 45% or at least 50%.

In some embodiments, after pyrolysis the target portion has a pyrolyzed permeability of at least 0.4 mD or at least 0.5 mD or at least 0.75 mD or at least 1 mD or at least 5 mD or at least 10 mD.

In some embodiments, an unpyrolyzed permeability of surrounding zone of the oil shale formation that substantially surrounds the targeted region is at most 0.2 mD, or at most 0.1 mD.

In some embodiments, after pyrolysis, a permeability ratio between: i. a pyrolyzed permeability that prevails throughout substantially an entirety of the target portion and ii. an unpyrolyzed permeability of surrounding zone of the oil shale formation that substantially surrounds the targeted region is at least 3:1, or at least 5:1 or at least 7:1 or at least 10:1.

In some embodiments, after pyrolysis, a porosity ratio between: i. a pyrolyzed porosity that prevails throughout substantially an entirety of the target portion and ii. an unpyrolyzed porosity of surrounding zone of the oil shale formation that substantially surrounds the targeted region is at least 1.2:1.

In some embodiments, a thermal conductivity of the surrounding zone of the oil shale formation that substantially surrounds the targeted region is at most 1.5 watt/(meter degree kelvin).

In some embodiments, during the storage phase, pyrolysis gases are produced via production wells so as to regulate a downhole pressure of the target region below a fracture initiation pressure.

In some embodiments, during the storage phase, pyrolysis gases are produced via production wells so as to regulate a downhole pressure of the target region below hydrostatic pressure.

In some embodiments, a depth of the target region or a depth of storage is at most 1,500 meters or at most 1,000 meters or at most 750 meters or at most 500 meters or at most 400 meters or at most 300 meters.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts a schematic view of an embodiment of a portion of the in situ heat treatment system for treating the hydrocarbon containing formation.

FIGS. 2-11 relate to various aspects of subsurface storage of hydrocarbon fluids (e.g. hot fluids) within an oil shale formation (e.g. previously pyrolyzed portion thereof).

DETAILED DESCRIPTION OF EMBODIMENTS

Embodiments of the present invention relate to a technique for creating a strategic reserve of hydrocarbon fluids by (i) filling pore space of a post-pyrolysis oil shale formation (e.g. at a depth of at least 100 meters, or at least 200 meters or at least 400 meters) with hot hydrocarbon fluids, and (ii) maintaining a wellhead pressure of production wells deployed in the oil shale (e.g. a kerogenous chalk) formation at an elevated pressure (i.e. at least 20 atmospheres, or at least 30 atmospheres, or at least 40 atmospheres or greater) for an extended period of time (i.e. at least several months or at least one year or at least several years) so as to retain the hydrocarbon fluids within the pore space. When the wellhead pressure of the production wells is subsequently reduced, after the extended period of time, hydrocarbon fluids are recovered from the strategic reserve.

Examples of hydrocarbon fluids that may be stored within the pore space of the post-pyrolysis oil shale formation include pyrolysis fluids (see for example FIGS. 3A, 8-9, 13-17), and stabilized unhydrotreated synthetic condensate (SUSC) derivatives of pyrolysis fluids (see for example, FIG. 3B and FIGS. 18-20).

In some embodiments of the present invention, one or more of the following features that are typically associated with conventional strategic reserves may be provided in the context of hydrocarbon fluid storage within pore space of post-pyrolysis oil shale: (i) hydrocarbon fluid containment; (ii) storage efficiency; (iii) hydrocarbon fluid accessibility; and (iv) hydrocarbon fluids usability.

As for the containment feature, in some embodiments stored hot hydrocarbon fluids are confined over an extended period of time within a post-pyrolysis target region of the oil shale formation without substantial hydrocarbon fluid migration to adjacent locations that are unpyrolyzed and/or water-saturated (see, for example, FIGS. 4A-4B, 5-6 and the related discussions).

As for storage efficiency, in some embodiments, production wells are operated at significantly elevated pressure so as to store pyrolysis fluids primarily in the liquid phase, (see FIGS. 8-9), taking advantage of the fact that liquids are significantly denser than gases. The elevated back pressure provided by the production wells also may hinder upward movement of hydrocarbon fluids through the production wells and out of the formation, thereby increasing the fraction of hydrocarbon fluids sustainably stored within pore space of the post-pyrolysis formation, and thereby increasing the storage efficiency. Another storage efficiency-related feature, discussed below with reference to FIGS. 4A-4B, 5A-5B, relates to the fact that a porosity of previously-pyrolyzed oil shale significantly exceeds that of unpyrolyzed oil shale. As such, a greater volumetric fraction of the post-pyrolysis formation is available to store hot hydrocarbon fluids.

As for hydrocarbon fluid accessibility and flowability, in some embodiments, before or during recovery, production wells are operated at sufficiently low pressure so that formerly-liquid phase C7+ or C9+ or C10+ (i.e. that have been stored in pore space of the formation for the extended period of time) exit the target region of the formation, and flow through production wells, as a gas or a multi-phase gas-mixture (see FIG. 12). Thus, in some embodiments, at least some of the stored hydrocarbon liquids flash into the gas phase. Because gas-phase viscosity of hydrocarbon fluids (see FIG. 11) is significantly less than liquid-phase viscosity (see FIG. 10), gas-phase hydrocarbon fluids recovery is useful for accessibility and flowability. Furthermore, even liquid-phase hydrocarbon fluids that flow towards the production wells within the target region of the oil shale formation are hot enough (see FIG. 10) so that they are not considered viscous fluids. For example, even liquid-phase hydrocarbon fluids present within the post-pyrolysis hot formation in the liquid phase may have viscosities of at most 0.5 cP.

As for fluid usability, in some embodiments pyrolysis fluids stored in situ may be transformed, upon recovery, into a stable pipelinable stabilized unhydrotreated synthetic condensate (SUSC) by (i) condensation cooling and/or (ii) steam stripping and/or (iii) distillation and/or (iv) sour water treatment (see FIGS. 17-20). This may be accomplished for example, without hydrotreating and/or without the need to co-locate the hydrocarbon strategic reserve facility with a hydrotreatment facility.

For convenience, in the context of the description herein, various terms are presented here. To the extent that definitions are provided, explicitly or implicitly, here or elsewhere in this application, such definitions are understood to be consistent with the usage of the defined terms by those of skill in the pertinent art(s). Furthermore, such definitions are to be construed in the broadest possible sense consistent with such usage.

The following description generally relates to systems and methods for treating hydrocarbons in the formations. Such formations may be treated to yield hydrocarbon products, hydrogen, and other products.

Unless specified otherwise, for the present disclosure, when two quantities QUANT₁ and QUANT₂, are ‘about’ equal to each other or ‘substantially equal’ to each other, the quantities are either exactly equal, or a ‘quantity ratio’ between (i) the greater of the two quantities MAX(QUANT₁, QUANT₂) and (ii) the lesser of the two quantities MIN(QUANT₁, QUANT₂) is at most 1.3. In some embodiments, this ratio is at most 1.2 or at most 1.1 or at most 1.05. In the present disclosure, ‘about’ equal and ‘substantially equal’ are used interchangeably and have the same meaning.

In the context of reduced heat output heating systems, apparatus, and methods, the term “automatically” means such systems, apparatus, and methods function in a certain way without the use of external control (for example, external controllers such as a controller with a temperature sensor and a feedback loop, PID controller, or predictive controller).

For the present disclosure, molecules of CN+ hydrocarbons each include at least N carbon atoms, where N is a positive integer. For example, C7+ hydrocarbons include at least 7 hydrocarbons.

A heater ‘cross section’ may vary along its central axis. Unless specified otherwise, a heater ‘cross section’ is the cross section in the plane in which a ‘heater pattern’ is defined. Unless specified otherwise, for a given heater pattern, the ‘cross sections’ of each of the heaters are all co-planar.

The term ‘displacement’ is used interchangeably with ‘distance.’

A ‘distance’ between a location and a heater is the distance between the location and a ‘centroid’ of the heater (i.e. a ‘centroid’ of the heater cross section in the plane in which a ‘heater pattern’ is defined). The ‘distance between multiple heaters’ is the distance between their centroids.

Unless specified otherwise, an ‘extended’ period of time is at least several (i.e. at least three or at least six) months. In some embodiments, the extended period of time may be at least one year, or at least two years, or at least three years, or at least five years, or a least ten years.

When pore space is ‘filled’ with a hydrocarbon fluid then the pore space is partially or completely filled with the hydrocarbon fluid.

A “formation” includes one or more hydrocarbon containing layers, one or more non-hydrocarbon layers, an overburden, and/or an underburden. “Hydrocarbon layers” refer to layers in the formation that contain hydrocarbons. The hydrocarbon layers may contain non-hydrocarbon material and hydrocarbon material. The “overburden” and/or the “underburden” include one or more different types of impermeable materials. For example, the overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate. In some embodiments of in situ heat treatment processes, the overburden and/or the underburden may include a hydrocarbon containing layer or hydrocarbon containing layers that are relatively impermeable and are not subjected to temperatures during in situ heat treatment processing that result in significant characteristic changes of the hydrocarbon containing layers of the overburden and/or the underburden. For example, the underburden may contain shale or mudstone, but the underburden is not allowed to heat to pyrolysis temperatures during the in situ heat treatment process. In some cases, the overburden and/or the underburden may be somewhat permeable.

“Formation fluids” refer to fluids present in a formation and may include pyrolyzation fluid, synthesis gas, mobilized hydrocarbons, and water (steam). Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids. “Produced fluids” refer to fluids removed from the subsurface formation.

A ‘governing wellhead pressure’ of a production well is a wellhead pressure which governs or determines the downhole pressure within the formation or a portion thereof (for example, a ‘significant portion’ thereof). During hydrocarbon fluids storage, the wellhead pressure and the downhole pressure may, approximately, have the same value.

When a target portion of the formation is at a wellhead pressure′ (or ‘maintained at a wellhead pressure’) this relates to the value of the governing wellhead pressures of production wells deployed therein. The ‘wellhead pressure’ of a formation (or a portion or target portion thereof) is at the ‘governing wellhead pressure’ of production well(s) deployed therein.

A “heat source” is any system for providing heat to at least a portion of a formation substantially by conductive and/or radiative heat transfer. For example, a heat source may include electric heaters such as an insulated conductor, an elongated member, and/or a conductor disposed in a conduit. A heat source may also include systems that generate heat by burning a fuel external to or in a formation. The systems may be surface burners, downhole gas burners, flameless distributed combustors, and natural distributed combustors. In some embodiments, heat provided to or generated in one or more heat sources may be supplied by other sources of energy. The other sources of energy may directly heat a formation, or the energy may be applied to a transfer medium that directly or indirectly heats the formation. It is to be understood that one or more heat sources that are applying heat to a formation may use different sources of energy. Thus, for example, for a given formation some heat sources may supply heat from electric resistance heaters, some heat sources may provide heat from combustion, and some heat sources may provide heat from one or more other energy sources (for example, chemical reactions, solar energy, wind energy, biomass, or other sources of renewable energy). A chemical reaction may include an exothermic reaction (for example, an oxidation reaction). A heat source may also include a heater that provides heat to a zone proximate and/or surrounding a heating location such as a heater well.

A “heater” is any system or heat source for generating heat in a well or a near wellbore region. Heaters may be, but are not limited to, electric heaters, burners (e.g. gas burners), pipes through which hot heat transfer fluid (e.g. molten salt or molten metal) flows, combustors that react with material in or produced from a formation, and/or combinations thereof. Unless specified otherwise, a ‘heater’ includes elongate portion having a length that is much greater than cross-section dimensions. One example of a ‘heater’ is a ‘molten salt heater’ where hot molten salt flows within a subsurface conduit and thermal energy is transferred directly or indirectly from the flowing molten salt to the subsurface formation.

“Heavy hydrocarbons” are viscous hydrocarbon fluids. Heavy hydrocarbons may include highly viscous hydrocarbon fluids such as heavy oil, tar, and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, as well as smaller concentrations of sulfur, oxygen, and nitrogen. Additional elements may also be present in heavy hydrocarbons in trace amounts. Heavy hydrocarbons may be classified by API gravity.

Heavy hydrocarbons generally have an API gravity below about 20°. Heavy oil, for example, generally has an API gravity of about 10-20°, whereas tar generally has an API gravity below about 10°. The viscosity of heavy hydrocarbons is generally greater than about 100 centipoise at 15° C. Heavy hydrocarbons may include aromatics or other complex ring hydrocarbons.

Unless specified otherwise, the term ‘hot’ fluid refers to a temperature of at least 150 degrees Celsius, or at least 200 degrees Celsius, or at least 250 degrees Celsius, at least 300 degrees Celsius.

“Hydrocarbons” are generally defined as molecules formed primarily by carbon and hydrogen atoms. Hydrocarbons may also include other elements such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to, kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, and asphaltites. Hydrocarbons may be located in or adjacent to mineral matrices in the earth. Matrices may include, but are not limited to, sedimentary rock, sands, silicilytes, carbonates, diatomites, and other porous media. “Hydrocarbon fluids” are fluids that include hydrocarbons. Hydrocarbon fluids may include, entrain, or be entrained in non-hydrocarbon fluids such as hydrogen, nitrogen, carbon monoxide, carbon dioxide, hydrogen sulfide, water, and ammonia.

An “in situ conversion process” refers to a process of heating a hydrocarbon containing formation from heat sources to raise the temperature of at least a portion of the formation above a pyrolysis temperature so that pyrolyzation fluid is produced in the formation.

An “in situ heat treatment process” refers to a process of heating a hydrocarbon containing formation with heat sources to raise the temperature of at least a portion of the formation above a temperature that results in mobilized fluid, visbreaking, and/or pyrolysis of hydrocarbon containing material so that mobilized fluids, visbroken fluids, and/or pyrolyzation fluids are produced in the formation.

“Kerogen” is a solid, insoluble hydrocarbon that has been converted by natural degradation and that principally contains carbon, hydrogen, nitrogen, oxygen, and sulfur. Coal and oil shale are typical examples of materials that contain kerogen. “Bitumen” is a non-crystalline solid or viscous hydrocarbon material that is substantially soluble in carbon disulfide. “Oil” is a fluid containing a mixture of condensable hydrocarbons.

“Production” of a hydrocarbon fluid refers to thermally generating the hydrocarbon fluid (e.g. from kerogen or bitumen) and removing the fluid from the sub-surface formation via a production well.

“Pyrolysis” is the breaking of chemical bonds due to the application of heat. For example, pyrolysis may include transforming a compound into one or more other substances by heat alone. Heat may be transferred to a section of the formation to cause pyrolysis.

When a kerogen-containing formation is pyrolyzed then organic matter therein is subjected to pyrolyis. After the pyrolyzation the formation may be considered a ‘post-pyrolysis formation’ or a ‘previously pyrolyzed formation’ which are used herein synonymously. The ‘post-pyrolysis formation’ or a ‘previously pyrolyzed formation’ may be very hot (e.g. around a pyrolysis temperature) or may have cooled to a temperature that is ‘significantly below’ a pyrolysis temperature.

“Pyrolyzation fluids” or “pyrolysis products” refers to fluid produced substantially during pyrolysis of hydrocarbons. Fluid produced by pyrolysis reactions may mix with other fluids in a formation. The mixture would be considered pyrolyzation fluid or pyrolyzation product. As used herein, “pyrolysis zone” refers to a volume of a formation (for example, a relatively permeable formation such as a tar sands formation) that is reacted or reacting to form a pyrolyzation fluid.

Unless specified otherwise, when a first quantity QUANT₁ ‘significantly exceeds’ a second quantity QUANT₂, a ratio between (i) the greater of the two quantities MAX(QUANT₁, QUANT₂) and (ii) the lesser of the two quantities MIN(QUANT₁, QUANT₂) is at least 1.5. In some embodiments, this ratio is at least 1.7 or at least 1.9.

Unless specified otherwise, a ‘significant majority’ refers to at least 75%. In some embodiments, the significant majority may be at least 80% or at least 85% or at least 90%.

Unless specified otherwise, a ‘significantly elevated pressure’ (e.g. wellhead pressure or downhole pressure is at least 20 atmospheres. In some embodiments, the “significantly elevated pressure’ may be at least 30 atmospheres, or at least 40 atmospheres, or at least 50 atmospheres, or at least 60 atmospheres.

A ‘significant portion’ of a subsurface formation (e.g. oil shale formation) has a length and width at least 50 meters and a height/thickness of at least 20 meters. In some embodiments, the length and the width is at least 100 meters or at least 200 meters or at least 300 meters. In some embodiments, the height/thickness is at least 50 meters or at least 75 meters or at least 100 meters.

“Superposition of heat” refers to providing heat from two or more heat sources to a selected section of a formation such that the temperature of the formation at least at one location between the heat sources is influenced by the heat sources.

A temperature that is ‘significantly below an oil shale pyrolysis temperature’ is a temperature where a ‘characteristic time’ of pyrolysis reactions of kerogen of the oil shale is quite ‘slow’—e.g. at least 10 years or at least 50 years.

“Tar” is a viscous hydrocarbon that generally has a viscosity greater than about 10,000 centipoise at 15° C. The specific gravity of tar generally is greater than 1.000. Tar may have an API gravity less than 10°.

“Thermally conductive fluid” includes fluid that has a higher thermal conductivity than air at standard temperature and pressure (STP) (0° and 101.325 kPa).

“Thermal conductivity” is a property of a material that describes the rate at which heat flows, in steady state, between two surfaces of the material for a given temperature difference between the two surfaces.

“Thickness” of a layer refers to the thickness of a cross section of the layer, wherein the cross section is normal to a face of the layer.

A “U-shaped wellbore” refers to a wellbore that extends from a first opening in the formation, through at least a portion of the formation, and out through a second opening in the formation. In this context, the wellbore may be only roughly in the shape of a “V” or “U”, with the understanding that the “legs” of the “U” do not need to be parallel to each other, or perpendicular to the “bottom” of the “U” for the wellbore to be considered “U-shaped”.

“Upgrade” refers to increasing the quality of hydrocarbons. For example, upgrading heavy hydrocarbons may result in an increase in the API gravity of the heavy hydrocarbons.

“Viscosity” refers to kinematic viscosity at 40° unless otherwise specified. Viscosity is as determined by ASTM Method D445.

“VGO” or “vacuum gas oil” refers to hydrocarbons with a boiling range distribution between 343° and 538° at 0.101 MPa. VGO content is determined by ASTM Method D5307.

The term “wellbore” refers to a hole in a formation made by drilling or insertion of a conduit into the formation. A wellbore may have a substantially circular cross section, or another cross-sectional shape. As used herein, the terms “well” and “opening,” when referring to an opening in the formation may be used interchangeably with the term “wellbore.”

A formation may be treated in various ways to produce many different products. Different stages or processes may be used to treat the formation during an in situ heat treatment process. In some embodiments, one or more sections of the formation are solution mined to remove soluble minerals from the sections. Solution mining minerals may be performed before, during, and/or after the in situ heat treatment process. In some embodiments, the average temperature of one or more sections being solution mined may be maintained below about 120° C.

In some embodiments, one or more sections of the formation are heated to remove water from the sections and/or to remove methane and other volatile hydrocarbons from the sections. In some embodiments, the average temperature may be raised from ambient temperature to temperatures below about 220° during removal of water and volatile hydrocarbons.

In some embodiments, one or more sections of the formation are heated to temperatures that allow for movement and/or visbreaking of hydrocarbons in the formation. In some embodiments, the average temperature of one or more sections of the formation are raised to mobilization temperatures of hydrocarbons in the sections (for example, to temperatures ranging from 100° to 250°, from 120° to 240°, or from 150° to) 230°.

In some embodiments, one or more sections are heated to temperatures that allow for pyrolysis reactions in the formation. In some embodiments, the average temperature of one or more sections of the formation may be raised to pyrolysis temperatures of hydrocarbons in the sections (for example, temperatures ranging from 230° to 900°, from 240° to 400° or from 250° to 350°).

Heating the hydrocarbon containing formation with a plurality of heat sources may establish thermal gradients around the heat sources that raise the temperature of hydrocarbons in the formation to desired temperatures at desired heating rates. The rate of temperature increase through mobilization temperature range and/or pyrolysis temperature range for desired products may affect the quality and quantity of the formation fluids produced from the hydrocarbon containing formation. Slowly raising the temperature of the formation through the mobilization temperature range and/or pyrolysis temperature range may allow for the production of high quality, high API gravity hydrocarbons from the formation. Slowly raising the temperature of the formation through the mobilization temperature range and/or pyrolysis temperature range may allow for the removal of a large amount of the hydrocarbons present in the formation as hydrocarbon product.

In some in situ heat treatment embodiments, a portion of the formation is heated to a desired temperature (e.g. pyrolysis temperature) instead of slowly heating the temperature through a temperature range. In some embodiments, the desired pyrolysis temperature is 300°, 325°, or 350° Other temperatures may be selected as the desired temperature.

Superposition of heat from heat sources allows the desired temperature to be relatively quickly and efficiently established in the formation. Energy input into the formation from the heat sources may be adjusted to maintain the temperature in the formation substantially at a desired temperature.

Mobilization and/or pyrolysis products may be produced from the formation through production wells. In some embodiments, the average temperature of one or more sections is raised to mobilization temperatures and hydrocarbons are produced from the production wells. The average temperature of one or more of the sections may be raised to pyrolysis temperatures after production due to mobilization decreases below a selected value. In some embodiments, the average temperature of one or more sections may be raised to pyrolysis temperatures without significant production before reaching pyrolysis temperatures. Formation fluids including pyrolysis products may be produced through the production wells.

In some embodiments, the average temperature of one or more sections may be raised to temperatures sufficient to allow synthesis gas production after mobilization and/or pyrolysis. In some embodiments, hydrocarbons may be raised to temperatures sufficient to allow synthesis gas production without significant production before reaching the temperatures sufficient to allow synthesis gas production. For example, synthesis gas may be produced in a temperature range from about 400° to about 1200°, about 500° to about 1100°, or about 550° to about 1000° A synthesis gas generating fluid (for example, steam and/or water) may be introduced into the sections to generate synthesis gas. Synthesis gas may be produced from production wells.

Solution mining, removal of volatile hydrocarbons and water, mobilizing hydrocarbons, pyrolyzing hydrocarbons, generating synthesis gas, and/or other processes may be performed during the in situ heat treatment process. In some embodiments, some processes may be performed after the in situ heat treatment process. Such processes may include, but are not limited to, recovering heat from treated sections, storing fluids (for example, water and/or hydrocarbons) in previously treated sections, and/or sequestering carbon dioxide in previously treated sections.

FIG. 1 depicts a schematic view of an embodiment of a portion of the in situ heat treatment system for treating the hydrocarbon containing formation. The in situ heat treatment system may include barrier wells 1200. Barrier wells are used to form a barrier around a treatment area. The barrier inhibits fluid flow into and/or out of the treatment area. Barrier wells include, but are not limited to, dewatering wells, vacuum wells, capture wells, injection wells, grout wells, freeze wells, or combinations thereof. In some embodiments, barrier wells 1200 are dewatering wells. Dewatering wells may remove liquid water and/or inhibit liquid water from entering a portion of the formation to be heated, or to the formation being heated. In the embodiment depicted in FIG. 1, the barrier wells 1200 are shown extending only along one side of heater sources 1202, but the barrier wells typically encircle all heat sources 1202 used, or to be used, to heat a treatment area of the formation.

Heat sources 1202 are placed in at least a portion of the formation. Heat sources 1202 may include heaters such as insulated conductors, conductor-in-conduit heaters, surface burners, flameless distributed combustors, and/or natural distributed combustors. Heat sources 1202 may also include other types of heaters. Heat sources 1202 provide heat to at least a portion of the formation to heat hydrocarbons in the formation. Energy may be supplied to heat sources 1202 through supply lines 1204. Supply lines 1204 may be structurally different depending on the type of heat source or heat sources used to heat the formation. Supply lines 1204 for heat sources may transmit electricity for electric heaters, may transport fuel for combustors, or may transport heat exchange fluid that is circulated in the formation. In some embodiments, electricity for an in situ heat treatment process may be provided by a nuclear power plant or nuclear power plants. The use of nuclear power may allow for reduction or elimination of carbon dioxide emissions from the in situ heat treatment process.

When the formation is heated, the heat input into the formation may cause expansion of the formation and geomechanical motion. The heat sources may be turned on before, at the same time, or during a dewatering process. Computer simulations may model formation response to heating. The computer simulations may be used to develop a pattern and time sequence for activating heat sources in the formation so that geomechanical motion of the formation does not adversely affect the functionality of heat sources, production wells, and other equipment in the formation.

Heating the formation may cause an increase in permeability and/or porosity of the formation. Increases in permeability and/or porosity may result from a reduction of mass in the formation due to vaporization and removal of water, removal of hydrocarbons, and/or creation of fractures. Fluid may flow more easily in the heated portion of the formation because of the increased permeability and/or porosity of the formation. Fluid in the heated portion of the formation may move a considerable distance through the formation because of the increased permeability and/or porosity. The considerable distance may be over 1000 m depending on various factors, such as permeability of the formation, properties of the fluid, temperature of the formation, and pressure gradient allowing movement of the fluid. The ability of fluid to travel considerable distance in the formation allows production wells 1206 to be spaced relatively far apart in the formation.

Production wells 1206 are used to remove formation fluid from the formation. In some embodiments, production well 1206 includes a heat source. The heat source in the production well may heat one or more portions of the formation at or near the production well. In some in situ heat treatment process embodiments, the amount of heat supplied to the formation from the production well per meter of the production well is less than the amount of heat applied to the formation from a heat source that heats the formation per meter of the heat source. Heat applied to the formation from the production well may increase formation permeability adjacent to the production well by vaporizing and removing liquid phase fluid adjacent to the production well and/or by increasing the permeability of the formation adjacent to the production well by formation of macro and/or micro fractures.

More than one heat source may be positioned in the production well. A heat source in a lower portion of the production well may be turned off when superposition of heat from adjacent heat sources heats the formation sufficiently to counteract benefits provided by heating the formation with the production well. In some embodiments, the heat source in an upper portion of the production well may remain on after the heat source in the lower portion of the production well is deactivated. The heat source in the upper portion of the well may inhibit condensation and reflux of formation fluid.

In some embodiments, the heat source in production well 1206 allows for vapor phase removal of formation fluids from the formation. Providing heating at or through the production well may: (1) inhibit condensation and/or refluxing of production fluid when such production fluid is moving in the production well proximate the overburden, (2) increase heat input into the formation, (3) increase production rate from the production well as compared to a production well without a heat source, (4) inhibit condensation of high carbon number compounds (C₆ hydrocarbons and above) in the production well, and/or (5) increase formation permeability at or proximate the production well.

Subsurface pressure in the formation may correspond to the fluid pressure generated in the formation. As temperatures in the heated portion of the formation increase, the pressure in the heated portion may increase as a result of thermal expansion of in situ fluids, increased fluid generation and vaporization of water. Controlling rate of fluid removal from the formation may allow for control of pressure in the formation. Pressure in the formation may be determined at a number of different locations, such as near or at production wells, near or at heat sources, or at monitor wells.

In some hydrocarbon containing formations, production of hydrocarbons from the formation is inhibited until at least some hydrocarbons in the formation have been mobilized and/or pyrolyzed. Formation fluid may be produced from the formation when the formation fluid is of a selected quality. In some embodiments, the selected quality includes an API gravity of at least about 20°, 30°, or 40°. Inhibiting production until at least some hydrocarbons are mobilized and/or pyrolyzed may increase conversion of heavy hydrocarbons to light hydrocarbons. Inhibiting initial production may minimize the production of heavy hydrocarbons from the formation. Production of substantial amounts of heavy hydrocarbons may require expensive equipment and/or reduce the life of production equipment.

In some hydrocarbon containing formations, hydrocarbons in the formation may be heated to mobilization and/or pyrolysis temperatures before substantial permeability has been generated in the heated portion of the formation. An initial lack of permeability may inhibit the transport of generated fluids to production wells 1206. During initial heating, fluid pressure in the formation may increase proximate heat sources 1202. The increased fluid pressure may be released, monitored, altered, and/or controlled through one or more heat sources 1202. For example, selected heat sources 1202 or separate pressure relief wells may include pressure relief valves that allow for removal of some fluid from the formation.

In some embodiments, pressure generated by expansion of mobilized fluids, pyrolysis fluids or other fluids generated in the formation may be allowed to increase although an open path to production wells 1206 or any other pressure sink may not yet exist in the formation. The fluid pressure may be allowed to increase towards a lithostatic pressure. Fractures in the hydrocarbon containing formation may form when the fluid approaches the lithostatic pressure. For example, fractures may form from heat sources 1202 to production wells 1206 in the heated portion of the formation. The generation of fractures in the heated portion may relieve some of the pressure in the portion. Pressure in the formation may have to be maintained below a selected pressure to inhibit unwanted production, fracturing of the overburden or underburden, and/or coking of hydrocarbons in the formation.

After mobilization and/or pyrolysis temperatures are reached and production from the formation is allowed, pressure in the formation may be varied to alter and/or control a composition of formation fluid produced, to control a percentage of condensable fluid as compared to non-condensable fluid in the formation fluid, and/or to control an API gravity of formation fluid being produced. For example, decreasing pressure may result in production of a larger condensable fluid component. The condensable fluid component may contain a larger percentage of olefins.

In some in situ heat treatment process embodiments, pressure in the formation may be maintained high enough to promote production of formation fluid with an API gravity of greater than 20°. Maintaining increased pressure in the formation may inhibit formation subsidence during in situ heat treatment. Maintaining increased pressure may reduce or eliminate the need to compress formation fluids at the surface to transport the fluids in collection conduits to treatment facilities.

Maintaining increased pressure in a heated portion of the formation may surprisingly allow for production of large quantities of hydrocarbons of increased quality and of relatively low molecular weight. Pressure may be maintained so that formation fluid produced has a minimal amount of compounds above a selected carbon number. The selected carbon number may be at most 25, at most 20, at most 12, or at most 8. Some high carbon number compounds may be entrained in vapor in the formation and may be removed from the formation with the vapor. Maintaining increased pressure in the formation may inhibit entrainment of high carbon number compounds and/or multi-ring hydrocarbon compounds in the vapor. High carbon number compounds and/or multi-ring hydrocarbon compounds may remain in a liquid phase in the formation for significant time periods. The significant time periods may provide sufficient time for the compounds to pyrolyze to form lower carbon number compounds.

Generation of relatively low molecular weight hydrocarbons is believed to be due, in part, to autogenous generation and reaction of hydrogen in a portion of the hydrocarbon containing formation. For example, maintaining an increased pressure may force hydrogen generated during pyrolysis into the liquid phase within the formation. Heating the portion to a temperature in a pyrolysis temperature range may pyrolyze hydrocarbons in the formation to generate liquid phase pyrolyzation fluids. The generated liquid phase pyrolyzation fluids components may include double bonds and/or radicals. Hydrogen (H₂) in the liquid phase may reduce double bonds of the generated pyrolyzation fluids, thereby reducing a potential for polymerization or formation of long chain compounds from the generated pyrolyzation fluids. In addition, H₂ may also neutralize radicals in the generated pyrolyzation fluids. H₂ in the liquid phase may inhibit the generated pyrolyzation fluids from reacting with each other and/or with other compounds in the formation.

Formation fluid produced from production wells 1206 may be transported through collection piping 1208 to treatment facilities 1210. Formation fluids may also be produced from heat sources 1202. For example, fluid may be produced from heat sources 1202 to control pressure in the formation adjacent to the heat sources. Fluid produced from heat sources 1202 may be transported through tubing or piping to collection piping 1208 or the produced fluid may be transported through tubing or piping directly to treatment facilities 1210. Treatment facilities 1210 may include separation units, reaction units, upgrading units, fuel cells, turbines, storage vessels, and/or other systems and units for processing produced formation fluids. The treatment facilities may form transportation fuel from at least a portion of the hydrocarbons produced from the formation. In some embodiments, the transportation fuel may be jet fuel, such as JP-8.

Formation fluid may be hot when produced from the formation through the production wells. Hot formation fluid may be produced during solution mining processes and/or during in situ heat treatment processes. In some embodiments, electricity may be generated using the heat of the fluid produced from the formation. Also, heat recovered from the formation after the in situ process may be used to generate electricity. The generated electricity may be used to supply power to the in situ heat treatment process. For example, the electricity may be used to power heaters, or to power a refrigeration system for forming or maintaining a low temperature barrier. Electricity may be generated using a Kalina cycle, Rankine cycle or other thermodynamic cycle. In some embodiments, the working fluid for the cycle used to generate electricity is aqua ammonia.

FIGS. 2 and 3A-3C flow charts of multi-phase techniques whereby: (i) pore space of a post-pyrolysis oil shale formation is filled with hot hydrocarbon fluids; (ii) the hydrocarbon fluids are stored, under pressure, for an extended period of time; and (iii) at a later time (e.g. in response to a demand triggering event such as a supply shock or natural disaster or an interruption in domestic petroleum production or an outbreak of hostilities), the operating pressure of production wells is reduced so as to recover the hot, stored hydrocarbon fluids from the pore space of the oil shale formation.

The example of FIG. 2 relates to any hydrocarbon fluid. In the example of FIG. 3A, a target region of oil shale is pyrolyzed so that hot hydrocarbon pyrolyzed fluids formed by the pyrolysis are stored in situ and under pressure within the pore space of the target region of oil shale. In the example of FIG. 3B, a stabilized oil derived from pyrolysis fluids is introduced into a previously-pyrolyzed region of oil shale where it is stored as a hot, pressurized fluid for an extended period of time.

In one example, the methods of FIG. 3A-3B may be preferred when it is desired to generate the largest possible hydrocarbon strategic reserve at the lowest possible price. This may be useful when a country wishes to insure itself, at minimal cost, against a protracted local or worldwide oil shortage. An advantage of the method of FIG. 3B is that SUSC is available whenever needed—however, the method of FIG. 3B requires additional resources to pre-stabilize the hydrocarbon fluids, and requires extra investment even when there is no immediate emergency. While the method of FIG. 3A enables establishment of a strategic resource at minimal cost, the storage hydrocarbon fluids may need to processed at a later stage (i.e. to reduce volatility and to remove sulfur-bearing molecules) before being pipelined.

One salient feature provided by all methods described in FIGS. 2 and 3A-3B is that production wells are operated at an elevated wellhead pressure (i.e. at least 20 atm, or at least 30 atm or at least 40 atm) for an extended period of time so as to retain and store hot hydrocarbon fluids within the formation. In some embodiments, the wellhead pressure is sufficient to maintain the hydrocarbon fluids substantially at or above a bubble curve thereof so that hydrocarbon liquids, rather than gases, are stored.

All of the methods described in FIGS. 2 and 3A-3B include: (i) a filling step S101 where pore space of a post-pyrolysis oil shale formation is filled by hot hydrocarbon fluids; (ii) a storage step S105 where production wells are operated so that the hot hydrocarbon fluids are maintained within the pore space, under pressure, for an extended period of time (e.g. substantially at or above a bubble curve of the fluids); and (iii) a recovery or production step S109 where a wellhead pressure of the production wells is reduced to enable recovery of the previously-stored hydrocarbon fluids. In some embodiments, the recovery S109 of the hydrocarbon fluids is carried out in response to any ‘demand triggering event’ (e.g. a supply shock or natural disaster or an interruption in domestic petroleum production or an outbreak of hostilities).

For the present disclosure, the term ‘filling’ does not require that hydrocarbon fluids or pyrolysis fluids occupy all pore space, and can also refer to situations where the pore space is at least partially filled. The term ‘filling with hot fluids’ does not require that the fluids are hot before occupying the pore space—the fluids only need to be hot upon occupying the pore space, and may or may not be ‘hot’ beforehand.

Reference is now made to FIG. 3A. During the dewatering phase of step S201, subsurface heaters 220 deployed in situ in a target portion of the oil shale formation sufficiently heat the target portion to vaporize liquid water present within pore space of the target portion into water vapor. The water present in pore space which is vaporized during watering S201 is not the same as ‘pyrolysis formation water’ which is a product of the pyrolysis reactions and only is generated at a later time, upon pyrolysis. During dewatering S201, the target portion dries as the water vapor migrates therefrom—this water vapor enters production wells and is recovered. Wellheads of the production wells are maintained substantially in an open configuration to allow water to flow through the production wells, relatively unhindered, out of the target portion of the oil shale configuration.

The subsurface heaters continue to heat the target portion of the oil shale formation until pyrolysis temperatures (e.g. between 290 and 340 degrees Celsius—in some preferred embodiments, around 320 degrees Celsius) are reached. During the pyrolysis phase of step S203 of FIG. 3A, while in a pyrolysis temperature range, kerogen (e.g. substantially all kerogen) within the target portion of the subsurface formation is pyrolyzed to yield hydrocarbon pyrolysis formation fluids.

Instead of immediately recovering pyrolysis formation fluids, in both the pyrolysis S203 and storage step S205, the target portion of the formation is maintained at an elevated wellhead pressure (e.g. at least 20 atmospheres). The ‘wellhead pressure’ is the pressure measured at wellheads of production wells. This is not necessarily the same as the ‘downhole pressure’ which is the pressure below the surface within the target portion of an oil shale formation. However, as will be discussed below, during the storage phase of the multi-phase technique, it is believed that the wellhead pressure governs the downhole pressure, that their values are substantially equal (within some tolerance).

For the present disclosure, the ‘governing wellhead pressure’ or the ‘wellhead pressure for a target portion of a formation’ is a wellhead pressure which effectively determines the bulk downhole pressure throughout the target portion of the oil shale formation, even if this downhole pressure differs from the wellhead pressure. In different embodiments, the ‘wellhead pressure of the target region’ or the ‘governing wellhead pressure’ is at least 20 atm (atmospheres), or at least 30 atm, or at least 40 atm, or at least 50 atm, or at least 60 atm. In some embodiments, the ‘wellhead pressure of the target region’ or the ‘governing wellhead pressure’ pressure is at most the fracture initiation pressure, or at most the lithostatic pressure, both of which depend upon depth of the target portion of the oil shale formation.

In step S209, the wellhead pressure is reduced for recovery of stored hydrocarbon fluids—for example, in response to any demand-triggering event.

In the example of FIG. 3A, the stored hydrocarbon fluids include fluids formed in situ by pyrolyzing the target portion of the oil shale formation. In contrast, in the method of FIG. 3B, the pyrolysis fluids generated in step S301 by pyrolyzing organic matter of a first oil shale target region or production area are recovered in step S302, via production wells. After processing (e.g. at the surface) of the pyrolysis fluids in step S303 to form a stabilized, unhydrotreated synthetic condensate (SUSC) therefrom, the SUSC is introduced in step S304 into a second oil shale target region or storage area which is (i) hot; (ii) previously-pyrolyzed and (iii) non-communicating with (i.e. not in fluid communication with) the first oil shale target region.

This processing is discussed in greater detail below with reference to FIGS. 18A-18C where the first oil shale target region or production area is labeled as 718 and the second oil shale target region or storage area is labeled as 710. Steps S305 and S309 of FIG. 3B are respectively similar to steps S205 and S209 of FIG. 3A, except the stored and recovered hydrocarbon fluid of FIG. 3B is a stabilized oil produced rather than in situ stored hydrocarbon pyrolysis formation fluids.

As mentioned above, in the method of FIG. 3A, the pyrolysis fluids recovered via production wells in step S209 may need to be stabilized and/or stripped. In contrast, the stabilized, unhydrotreated synthetic condensate (SUSC) recovered in step S309 of FIG. 3B may be readily-pipelinable at standard operating conditions, having a greater level of usability then the pyrolysis fluids of FIG. 3A.

FIGS. 4A-4B respectively illustrate a target portion 800 of the oil shale formation before and after pyrolysis. Although FIGS. 4A-4B are discussed in the context of the method of FIG. 3A (i.e. in-situ storage of pyrolysis fluids), it is noted that the physical differences between a pyrolyzed target section of an oil shale formation and the unpyrolyzed (e.g. water-saturated) surrounding region of the oil shale formation may be present in other embodiments, such as those described above with reference to FIGS. 3B-3C.

FIGS. 4A-4B illustrate an apparatus for hydrocarbon fluid storage and recovery. Although all of the illustrated heaters 220 and production wells 224 are vertically oriented, this is not a limitation, and it is appreciated that the heater(s) 220 and/or production wells 224 may have other orientations such as horizontal or diagonal. The ‘depth’ of the target portion 800 of the oil shale formation, defined as the depth of a most shallow′ location therein, is at least 100 meters—in some embodiments, at least 200 meters, or at least 250 meters, or at least 300 meters, or at least 400 meters.

FIG. 4A illustrates the target portion 800A before pyrolysis while FIG. 4B illustrates the target portion 800B after pyrolysis. As will be discussed below in greater detail with reference to FIG. 5, pyrolysis of the target portion 800 may increase a permeability therein relative to that of the unpyrolyzed surrounding 810 zone—for example, by at least a factor of three, or at least a factor of five, or at least a factor of the ten. In some examples, the unpyrolyzed target portion 800A (see FIG. 4A) as well as the surrounding zone 810 may have a permeability of at most 0.2 millidarcy (mD) or at most 0.1 millidarcy (mD). In contrast, the pyrolyzed target portion 800B (see FIG. 4B) has a permeability of at least 0.4 mD, or at least 1 mD, or at least 5 mD, or at least 10 mD.

This is advantageous because, for the purpose of maintaining a strategic reserve of hydrocarbon fluids, it is important to contain the hydrocarbon fluids within a designated location from which they can be recovered upon demands. Furthermore, the fluid containment feature provided by the significant difference in permeability substantially eliminates any risk of hydrocarbon fluids (e.g. pyrolysis fluids or a stabilized oil) migrating into a location that is expected to be maintained free of hydrocarbon fluids, making the presently-described storage technique environmentally friendly.

As noted above with reference to step S201 of FIG. 3A, as the target portion 800 of the oil shale formation is heated above the boiling point of water, the target portion 800 is selectively dried (i.e. as water vapors exit the formation via production wells) while the surrounding zone 810 remains water saturated. Therefore, the relative permeability ratio between (i) the relative permeability of C7+ hydrocarbon fluids in the unpyrolyzed surrounding zone 810 and (ii) the relative permeability of C7+ hydrocarbon fluids in the pyrolyzed target portion 800B exceeds the absolute permeability ratio between (i) the absolute permeability of C7+ hydrocarbon fluids in the unpyrolyzed surrounding zone 810 and (ii) the absolute permeability of C7+ hydrocarbon fluids in the pyrolyzed target portion 800B. This is because the presence of water within the pore space of the surrounding zone 810 hinders transport of C7+ hydrocarbon fluids therein.

For the present disclosure, molecules of CN+ hydrocarbons each include at least N carbon atoms, where N is a positive integer.

FIG. 6 illustrates an example of the relative permeability of oil within a porous media. Assuming that the water saturation g of the surrounding zone exceeds 0.8, then the permeability of hydrocarbon pyrolysis fluids within the water-saturated surrounding zone 810 may be less than 0.005 mD, which is extremely low. The combination of high water saturation and low permeability of the surrounding zone 810 means (i) the hydrocarbon pyrolysis fluids are substantially unable to flow into the surrounding zone 810 and (ii) the surrounding zone 810 therefore serves as a natural barrier to flow, and functions to contain substantially all hydrocarbon pyrolysis fluids, even over an extended period of time, within the reservoir target portion 800 of the subsurface formation.

FIG. 5 describe various porosities and gas phase absolute permeabilities of lab samples of a Type IIs marine kerogenous chalk before pyrolysis (represented by diamonds) and after pyrolysis (represented by X's). Before pyrolysis, most porosities are between 30% and 40% while most absolute gas-phase permeabilities are between 0.01 and 0.1 mD. After pyrolysis, values of the both the permeabilities and the porosities increase. In the example illustrated in FIG. 5, the post-pyrolysis values of absolute permeability are mostly between 0.5 and 1.0 mD while the post-pyrolysis values of porosity almost all have a value between 50% and 60%.

Within the target portion of the oil shale formation, a bulk porosity will be some an average of various local values. In some embodiments, upon completion of the pyrolysis phase, a porosity ratio between: i. a pyrolyzed porosity that prevails substantially throughout an entirety of the target portion 800 and ii. an unpyrolyzed porosity of surrounding zone 810 of the oil shale formation that substantially surrounds the targeted region is at least 1.2:1, or at least 1.5:1. In this manner, subjecting the target portion 800 to pyrolysis before the storage phase actually increases a storage efficiency thereof, thereby storing more hydrocarbons in the target volume and reducing a number of production wells required to recover hydrocarbon fluids on demand from the target portion 800 of the formation.

Within the target portion of the oil shale formation, a bulk pemeability will be an average of various local values. In some embodiments, upon completion of the pyrolysis phase, a permeability ratio between: i. a pyrolyzed permeability that prevails throughout substantially an entirety of the target portion 800 and ii. an unpyrolyzed permeability of surrounding zone 810 of the oil shale formation that substantially surrounds the targeted region is at least 3:1, or at least 5:1, or at least 10:1. Thus, as explained above, this permeability property allows the surrounding formation to contain hydrocarbon fluids within the target portion 800, which functions as a strategic reserve.

FIG. 7 illustrates the increase in porosity post-pyrolysis of the target portion of the formation 800, relative to an initial state. The fraction of the target portion initially occupied by solid-phase inorganic matrix is M_(PRE) where M is an abbreviation for matrix and the subscript PRE denotes ‘pre-pyrolyis;’ the fraction of the target portion initially occupied by solid-phase kerogen is K_(PRE) where K is an abbreviation for kerogen; the fraction of the target portion initially occupied by liquid-phase water is W_(PRE) where W is an abbreviation for water. Pre-pyrolysis, the following equation describes the volume fractions:

M _(PRE) +K _(PRE) +W _(PRE)=1.

Since all pore space is occupied by water, the pre-pyrolysis porosity Φ_(PRE) is exactly W_(PRE).

To determine the volume fraction K_(PRE) occupied by kerogen, it is possible to write the following equations:

ρ_(b) = ρ_(g) * (1 − W_(PRE) − K_(PRE)) + ρ_(WATER) * W_(PRE) + ρ_(KERO) * K_(PRE) $K_{PRE} = \frac{\left( {\rho_{b} - \rho_{g} + {W_{PRE}*\rho_{g}} - {W_{PRE}*\rho_{WATER}}} \right)}{\left( {\rho_{KERO} - \rho_{g}} \right)}$

where ρ_(b) is the overall bulk density of rock in the oil shale formation, ρ_(g) is the density of the inorganic matrix portion of the rock, and ρ_(kero) is the density of kerogen.

If ρ_(b)=1.7, ρ_(g)2.73, ρ_(kero)=1.03, and W_(PRE)=0.36, the equation yields K_(PRE)=0.24.

Post-pyrolysis, (i) all water has been vaporized and removed from the completely try target portion 800A (ii) the kerogen has been completely pyrolyzed yielding pyrolysis fluids and some sort or solid-phase residue of pyrolyzed kerogen. The pyrolysis process does not significantly modify the matrix/inorganic grains so that the fraction M_(POST) of the target portion of the formation by the matrix/inorganic grains is substantially equal to the fraction which prevailed pre-pyrolysis, i.e. M_(POST)=M_(PRE), where the subscript POST denotes ‘post-pyrolyis;’ Post-pyrolysis, the fraction of the target portion occupied by the solid-phase kerogen residue is R_(POST) where R is an abbreviation for residue. Post-pyrolysis, the pore space is not occupied by any solid-phase material—some or all of the pore space may be occupied by pyrolysis fluids. In contrast to the situation which prevailed pre-pyrolysis, no water may be observed within the pyrolyzed target portion 800B of the oil shale formation.

The post-pyrolysis porosity Φ_(POST) is given by 1−M_(POST)−R_(POST), which exceeds the pre-pyrolysis porosity Φ_(PRE). For the values of ρ_(b), ρ_(g), ρ_(KERO), W_(PRE) and K_(PRE) specified above, assuming that R_(POST)≈0.5*K_(PRE) yields Φ_(POST)≈0.48.

This relatively high porosity value facilitates relatively high storage efficiency of the hydrocarbon pyrolysis fluids, storing more hydrocarbons in the target volume and reducing the number of production wells required subsequent production, from the strategic reserve, of the stored hydrocarbon pyrolysis fluids.

Another feature which facilitates relatively high storage efficiency is the ability to stably store at least hot C7+ hydrocarbon fluids (for example, pyrolysis fluids according to the examples of FIGS. 3A, 13-16 or stabilized unhydrotreated synthetic condensate (SUSC) derived from pyrolysis fluids according to the examples of FIG. 3B and FIGS. 18-20.

FIGS. 5-7 relate to differential permeability to hydrocarbon fluids—this property is useful for containment of hydrocarbon fluids. Furthermore, FIGS. 5 and 7 relate to the porosity of post-pyrolysis oil shale. In particular, the relatively high porosity of kerogenous chalks is advantageous for storaging a hydrocarbon fluids efficiently.

FIGS. 8-9 also relate to the storage efficiency-related features. In particular, by operating production wells at an elevated pressure so that hydrocarbon fluids are at or above a bubble point curve, it is possible to take advantage of the fact that liquids are denser than gases, and to store the hydrocarbon fluids more efficiently than would be possible at lower pressures.

FIG. 8 illustrates a phase diagram of a mixture of hydrocarbon C5+ pyrolysis fluids resulting from pyrolyzing kerogen according a numerical simulation. The phase diagram of FIG. 8 is for a dry mixture in the absence of water produced by the pyrolysis reactions. As will be noted below with reference to FIGS. 15-16, during pyrolysis (see S203 of FIG. 3A) or thereafter (see S205) it is possible to operate production wells so as to separate water from the C5+ hydrocarbon pyrolysis formations fluids by recovering the water from the formation while leaving the hydrocarbon fluids beneath the surface in pore space of the post-pyrolysis oil shale.

As illustrated in FIG. 8, during the storage step S105 it is possible to operate production wells at an elevated pressure so that hydrocarbon fluids are stored in the post-pyrolysis oil shale formation in a liquid phase at or above the bubble point curve of the hydrocarbon fluids stored within the pore space of the oil shale formation. As illustrated in FIG. 8, during step S109 (for example, in response to a demand for the hydrocarbon fluids), reduction of the wellhead pressure may vaporize some or all of the hydrocarbon fluids, so that at least some of the hydrocarbon fluids is recovered as a gas. As discussed elsewhere in the present disclosure, this is useful for facilitating rapid access to the hydrocarbon fluids.

FIGS. 8-9 relate to the particular embodiment of FIG. 3A, where the stored hot hydrocarbon fluids are in situ pyrolysis formation fluids. However, the general principle illustrated in FIG. 8 of (i) storing at or above a bubble point so that pore space-stored hydrocarbon fluids are maintained in the liquid phase; and/or (ii) reducing wellhead production wells so that some or all of the hydrocarbon fluids are recovered as a vapor (i.e. for more rapid recovery—i.e. better accessibility to stored hydrocarbon fluids when there is a demand for them) may apply to other embodiments.

FIGS. 9A-9B relate to the embodiment of FIG. 3A, and illustrate the result of a simulation describing the mass fraction of hydrocarbon pyrolysis fluids that remain in the sub-surface after storage for an extended period of time as a function of (i) storage temperature and (ii) wellhead pressure of the oil shale formation. The ordinate of FIG. 9A, labeled as ‘mass fraction,’ is the ratio between (i) the mass of C5+ pyrolysis fluids remaining in the subsurface formation after extended-time storage and (ii) the initial mass of C5+ pyrolysis formation fluids generated by pyrolyzing kerogen therein. In FIG. 9B, the ordinate (also labeled as ‘mass fraction’) is the ratio between (i) the mass of C10-C20 pyrolysis fluids remaining in the subsurface formation after extended-time storage and (ii) the initial mass of C10-C20 pyrolysis formation fluids generated by pyrolyzing kerogen therein. Both the ‘mass fractions’ of FIG. 9A-9B are descriptive of the storage efficiency of hydrocarbon pyrolysis fluids.

As illustrated in FIGS. 9A-9B, the wellhead pressure of the post-pyrolysis oil shale formation where the pyrolysis fluids are stored has a strong influence on the storage efficiency. In the non-limiting example of FIGS. 9A-9B, at temperatures above 300 degrees Celsius, a wellhead pressure well above 20 atmospheres is required in order to retain 60% of the C5+ or C10-C20 pyrolysis fluids.

The simulation of FIGS. 9A-9B was carried out using the following inputs: (i) the PVT properties of pyrolysis fluids obtained by pyrolyzing Ghareb formation oil shale in the laboratory; (ii) a STARS (CMG, Calgary, Canada) simulation of in situ pyrolysis of kerogen of a kerogenous chalk so as to generate aqueous and hydrocarbon fluids; and (iii) a multi-step flash distillation simulation of the production wells as the target volume heats to pyrolysis temperatures. The simulation assumed that a dual phase production well was used and that a wellhead pressure governing the downhole pressure was sufficient so that water in the dual phase production well was sufficiently pressurized so as to exist as a liquid. The simulation assumed, as discussed below with reference to FIGS. 15-16, that (i) hydrogen, hydrogen sulfide, CO₂, and light hydrocarbon gases were recovered via the annular portion of the production well while (ii) liquid-phase brine derived from pyrolysis is pumped up and out of the formation through the production tubular portion of the production well by a pump located in a cold rathole below the heated zone.

FIGS. 8 and 9A-9C relate to storage efficiency of hydrocarbon fluids. FIGS. 8 and 10-11 relate to the property of hydrocarbon fluids accessibility on demand—i.e. the rate at which hot hydrocarbon fluids may be recovered from the post-pyrolysis oil shale formation.

For the present disclosure, the term ‘hot’ refers to a temperature of at least 150 degrees Celsius, or at least 200 degrees Celsius, or at least 250 degrees Celsius. As discussed below, when ‘hot’ liquids are stored their viscosity is significantly less than that of cooler fluids—this is useful for accessibility of fluid.

FIG. 10 illustrates viscosity as a function of temperature for a synthetic hydrocarbon condensate for example having properties similar to a mixture of C6+ pyrolysis fluids from the Ghareb formation. It is appreciated that the viscosity of other hydrocarbon fluids may be different.

As illustrated in FIG. 10, for hydrocarbon fluids, the dependence of liquid viscosity on temperature is considerable. The viscosity of hot hydrocarbon liquids is significantly less than at cooler temperatures. The viscosity of C6+ pyrolysis fluids or of other hot hydrocarbon liquids may be less than about 0.5 cP. By storing hydrocarbon fluids in the subsurface when they are hot, it is possible to take advantage of the fact that viscosity of the liquid-phase hydrocarbon fluids is low, and that these hydrocarbon liquids may flow towards production wells at a reasonable rate. This is useful for providing hydrocarbon fluids accessibility, potentially greater than what would be achievable at lower storage temperatures.

At a temperature of about 260 degrees Celsius, the viscosity of kerosene, distillate and 40 deg. API crude are all well below 0.5 cP. Assuming a target portion 800 has a thickness of at least 100 meters and a width and length equal to or exceeding 100 meters, the stored pyrolysis fluids cool quite slowly, due to the low thermal conductivity of surrounding zone which, in embodiments, is at most 1.5 Watt/(meter degree Kelvin).

Thus, even after the subsurface heaters are deenergized (e.g. when an average temperature within target portion 800B is at or near pyrolysis temperatures—for example, when the temperature is between 310 and 340 degrees Celsius), hydrocarbon pyrolysis fluids within pore space of the target portion 800B may remain ‘hot’ (e.g. at least 250 degrees Celsius) for many years. As noted earlier, because these hydrocarbon pyrolysis fluids remain hot, their viscosity is relatively low. Therefore, when the production phase commences, even if the post-pyrolysis permeability within the target portion 800B is no more than 1.0 mD, the hot pyrolysis fluids stored in the target portion 800B may still flow, relatively unhindered, towards the production wells, due to the low fluid viscosity. This allows for substantially on-demand production of hydrocarbon pyrolysis fluids from the strategic reserve.

Furthermore, the viscosity of hydrocarbon gases are even lower. During the production phase, the governing wellhead pressure (i.e. governing the downhole pressure) is significantly reduced, for example, to values less than 5 atm or less than 3 atm or substantially to atmospheric pressure. As illustrated in FIG. 11 the viscosity of hydrocarbon gases may be about one order of magnitude less than that of liquids. For this reason, as illustrated at FIG. 8, it may be advantageous to reduce the wellhead pressure of the formation significantly so as to vaporize some or most or all stored hydrocarbon fluids, in order to recover hydrocarbon fluids within a reasonable amount of time, thereby further ensuing fluids accessibility.

As noted above, during fluids recovery (see step S109 of FIG. 2), the wellhead pressure of the production wells (i.e. governing the downhole pressure) may be reduced significantly. When the wellhead pressure is reduced, the downhole pressure very close to production wells may drop relatively quickly and almost immediately, while at locations further away from the production wells the downhole pressure may drop at a slower rate and only after a time lag. This is illustrated in FIG. 12 which illustrates for earlier t₁ and later t₂ times, the local downhole pressure P as a function of a distance r from a production well.

It is noted that FIG. 12 is based upon theoretical and numerical calculations, and is not intended as limiting.

Four pressures are illustrated in FIG. 12—(i) the storage pressure P_(STORAGE) which prevails throughout the target region 800 during substantially the entire storage step S105—in some embodiments, a value of P_(STORAGE) is at least 20 atmospheres or greater (ii) the fluid production/recovery pressure P_(PRODUCTION) at which production wells are operated during fluid production/recovery of step S109—in some embodiments a value of P_(PRODUCTION) is less than about 2 atmospheres (e.g about one atmosphere or even lower); (iii) a bubble point pressure P_(BUBBLE) of the hydrocarbon fluids above which all fluids are liquids—for example, see the phase diagram of FIG. 8; (iv) a dew point pressure P_(DEw) of the hydrocarbon fluids below which all fluids are gases—for example, see the phase diagram of FIG. 8.

Also illustrated in FIG. 12 are the following four ordered pairs: (r_(t1) ^(D),P_(DEW)); (r_(t1) ^(B),P_(BUBBLE)); (r_(t2) ^(D),P_(DEW)) and (r_(t2) ^(B),P_(BUBBLE)). According to the ‘single production well’ example of FIG. 12, at the earlier time t₁, (i) at locations displaced from the production well by less than a ‘dew boundary’ distance r_(t1) ^(D), all hydrocarbon fluids are in the gas phase; (ii) at locations displaced from the production well by more than the ‘dew boundary’ distance r_(t1) ^(D) but less than a ‘bubble boundary’ distance r_(t1) ^(B), liquids and gases co-exist as a dual phase; and (iii) at locations displaced from the production well by more than the ‘bubble boundary’ distance r_(t1) ^(B), all hydrocarbon fluids are liquid.

According to the ‘single production well’ example of FIG. 12, at the later time t₂, (i) at locations displaced from the production well by less than a ‘dew boundary’ distance r_(t2) ^(D), substantially all hydrocarbon fluids are in the gas phase; (ii) at locations displaced from the production well by more than the ‘dew boundary’ distance r_(t2) ^(D) but less than a bubble boundary′ distance r_(t2) ^(B), liquids and gases co-exist as a dual phase; and (iii) at locations displaced from the production well by more than the ‘bubble boundary’ distance r_(t2) ^(B), substantially all hydrocarbon fluids are liquid.

As illustrated in FIG. 12, during the production step S109, both the dew boundary location r_(t) ^(D) and the bubble boundary location r_(t) ^(B) propagate away from the production well after a wellhead pressure thereof drops—i.e. both r_(t2) ^(D)>r_(t1) ^(D) and r_(t2) ^(B)>r_(t2) ^(B) are true. After enough time, a pressure quasi-equilibrium may be established within the target section 800 of the oil shale formation so that substantially all hydrocarbon fluids therein are gases.

FIGS. 13A-13B relate to the embodiment of FIG. 3A, and describe how subsurface heaters and production wells are operated during the dewatering S201, pyrolysis S203, storage S205, and recovery steps. During dewatering S201, it is desirable to immediately remove formation fluids (i.e. in this case water) from pore space of the target portion of the oil shale formation as it is heated. As such, during dewatering S201 (i) the subsurface heaters are operated at a power level sufficient to vaporize water embedded within pore space of the target region 800; and (ii) the wellheads of the production wells 224 deployed within the target portion of the oil shale formation are maintained S551 at substantially a low pressure (or in an open configuration) for fast recovery of water and steam from the subsurface formation via production wells.

In contrast, during the subsequent pyrolysis S203 and storage S205 steps, it is desired to retain and store hot hydrocarbon pyrolysis formation fluids within pore space of the target portion of the oil shale formation. During the pyrolysis and storage phase, at least C7+ pyrolysis fluids are retained deep beneath the surface by maintaining S255 the wellheads at an elevated pressure (e.g. at least 20 atmospheres). This elevated wellhead pressure substantially blocks at least C7+ hydrocarbon pyrolysis fluids from exiting the target portion of the oil shale formation and migrating upwards within production wells. As illustrated in the figures, during pyrolysis S505 the subsurface heaters continue to provide thermal energy to the target portion 800 of the oil shale formation. During the storage, a power level of subsurface heaters may be reduced—for example, as in step S509 where these heaters may be operated in shut-down mode. As mentioned elsewhere in the present document, and as illustrated in FIG. 13, during recovery the wellhead pressure of production wells may be significantly reduced S559 to recover stored pyrolysis fluids.

In the example of FIG. 13B, the production well is a dual-phase production well (see, for example, FIG. 15B). In some embodiments, in step S255 during pyrolysis and/or storage, the governing wellhead pressure of the production wells (i.e. pressure which governs the downhole pressure within the target region 800) is sufficient so that C7+ hydrocarbon fluids within pore space of the target region 800 exist primarily as a liquid. At these pressures, aqueous brine comprising pyroylsis formation water (i.e. water that is a reaction product of the pyorlysis of kerogen) may exist as a liquid, especially at locations near the production well and far from subsurface heaters. In step S561, a dual-phase production well may be used to simultaneously recover the following pyrolysis products: (i) liquid-phase brine—for example, via a production tubular inner portion of a dual-phase production well; and (ii) hydrocarbon gases—for example, via an annular outer portion of the dual-phase production well.

Recovering brine in the liquid phase may be preferable to recovering steam. Vapor phase recovery of pyrolysis-derived steam may strip the lighter components from stored C6+ pyrolysis fluids remaining within the post-pyrolysis target portion 800B (i.e. within pore space thereof). Thus, vapor-phase recovery of pyrolysis-derived water may reduce a quality (e.g. as measured by API gravity) of the remaining C6+ pyrolysis fluids and hinder their subsequent recovery (i.e. in step S109);

FIG. 14A illustrates a time-dependence of a power level of in situ heaters and bulk temperature of the target portion 800 of the oil shale formation as a function of time, in one example. FIG. 14B illustrates a time-dependence of a power level of in situ heaters and wellhead pressure of the target portion 800 as a function of time, according to the example of FIG. 14A. As the target portion 800 is preheated, the temperature bulk temperature therein steadily increases as a result of operating the in situ heaters at or near maximum power. As noted above with reference to step S551 of FIG. 13, during dewatering, the production wells are operated at low or very low pressure and the pressure of the target portion 800 remains low (see FIG. 14B).

After dewatering, as the formation continues to heat, wellhead pressure of the production wells is significantly increased to an elevated level—as discussed above, the elevated level may be at least 20 atm, or at least more. During a pyrolysis step, (i) the wellhead pressure is maintained at the elevated level; and (ii) in situ heaters continue to operate at or near maximum levels to continue to deliver thermal energy to the target portion of the oil shale formation.

Once pyrolysis reactions have substantially concluded, in situ storage of the hydrocarbon pyrolysis formation fluids may commence. In the non-limiting example of FIGS. 14A-14B, a power level of the in situ heaters is significantly reduced upon commencement of the storage S205 step, though reduction of power may occur earlier or later. Upon reduction of the power level, the target portion of the oil shale formation begins to cool very slowly.

Advantageously, the rate of cooling may be very slow, due to the low thermal conductivity (e.g. at most 1.5 watt/(meter ° C.) of the unpyrolyzed surrounding zone which surrounds the target portion of the oil shale formation. This is illustrated in FIG. 14A by the relatively shallow downward slope of the temperature curve during the extended storage phase.

In response to a demand to produce (e.g. a supply shock or natural disaster or an interruption in domestic petroleum production or an outbreak of hostilities), or for any other reason, the wellhead production may be significantly reduced so that the state of flow regulation in the production wells shift from almost ‘fully closed’ to ‘full open’ or nearly fully open. Upon commencement of step S209, the wellhead pressure drops and hydrocarbon fluids are recovered.

FIG. 15A illustrates a variety of subsurface heaters, observation wells, dewatering wells and ground water monitor wells that may be used in various embodiments.

FIG. 15B is a drawing of an exemplary dual phase production well including perforated casing and slotted linear. The dual phase production well includes an inner production tubular via which liquid-phase pyrolysis-derived brine is recovered and an annulus via which hydrogen, H₂S, carbon dioxide and light hydrocarbon gases are recovered.

Reference is made to FIGS. 16A-16D which describe the transport of pyrolysis-derived water (i.e. one of the products of pyrolysis reactions) from subsurface heaters 200 to production wells 224 during pyrolysis. Closer to the heaters 220 the pyrolysis-derived water is in the vapor phase while further from the heaters 220 this pyrolysis-derived water is a liquid. As illustrated in FIG. 16A (FRAME 1/4), at early stages of pyrolysis, only a relatively small portion of the oil shale formation is above a boiling point of water (i.e. at the downhole pressure). However, later times (see FIGS. 16B-16D), significant portions of the target portion 800 of the oil shale formation are sufficiently cool for pyrolysis-derived water to exist in the liquid phase. As such, most water generated by pyrolysis may be recovered in the liquid phase, for example, via the dual phase production well of FIG. 15B. In FIGS. 16A-16D respective temperature profiles are presented in each frame, where “water BP” is the boiling point of water at the downhole pressure (e.g. at least 20 atmospheres). Recovering the water substantially as a liquid reduces the tendency to steam strip (i.e. distill) the light hydrocarbon molecules.

The time dependence of the production well temperature was computed according to the numerical simulation. According to the results of this simulation, even though significant portions of the target region 800 are pyrolyzed, a temperature at the production wells 224 (i.e. which may be deployed at locations furthest from subsurface heaters 220) may reach around 260 degrees at the end of pyrolysis, significantly cooler than a local temperature at the subsurface heaters 220 and below the average pyrolysis temperature in the target zone.

FIGS. 13-17 relate to the embodiment of FIG. 3A. FIGS. 18-20 relate to the embodiment of FIG. 3B wherein a synthetic unhydrotreated condensate USC (SUSC) is introduced, in step S304, into pore space of a post-pyrolysis oil shale formation. In some embodiments, the SUSC is produced from hydrocarbon pyrolysis fluids of a first oil shale target region (labeled as the “production area” 718 in FIGS. 17A-17B) and the SUSC is introduced into a second oil shale target region (labeled as the “storage area” 710 in FIGS. 17A-17B) which was previously pyrolyzed.

One advantage of the method of FIG. 3B is that the synthetic unhydrotreated condensate USC (SUSC) may be pipelinable under standard conditions.

FIG. 18A illustrates a first implementation of the method of FIG. 3B whereby the production and storage areas are both located in the same oil shale formation. FIG. 18B illustrates a second implementation of the method of FIG. 3B whereby the production and storage areas are both located in the same oil shale formation. In both examples, the production 718 and storage 710 areas are non-communicating—there is substantially no sub-surface fluid flow between them.

In the non-limiting example of FIGS. 18A-18B, the following pyrolysis products are recovered from the production area, and illustrated as streams leaving: (i) a first stream comprising primarily gases including H₂S; and (ii) a second fluids stream comprising liquid or a mixture of liquid and gas—this second stream includes C5+ hydrocarbon pyrolysis fluids. The first stream may be sent to a refinery of treatment. The second stream is send to stripper/stabilizer 730 where the term ‘stripper’ denotes the stripping away of lighter hydrocarbon fractions along with H₂S while the term ‘stabilizer’ denotes the stabilizing function of the stripper/stabilizer unit 730. The stabilized fluid is then sent to dual-phase separator 734 which separates hydrocarbon components (i.e. to yield a stabilized unhydotreated synthetic condensate ‘SUSC’) from aqueous components (i.e. to yield a brine). The resulting SUSC is injected (e.g. via production well 224B) into pore space of the previously-pyrolyzed storage area 710 (see step S304 of FIG. 3B). The resulting brine is sent for treatment.

Storage area 710 may be hot—e.g. as a result of thermal inertia from the previous pyrolysis. As such, even if the SUSC is not necessarily hot (i.e. the SUSC may or may not be hot) as it enters the injection or production well (e.g. 224B) en route to the second storage area 710, within the second storage area 710 thermal energy of the previously-pyrolyzed hot oil shale formation may heat the SUSC so that the SUSC are, in fact, hot during storage. Storage of hot, pressurized SUSC within second storage area 710 may be useful for flashing at least some of the SUSC into the gas phase upon production during step S309 of FIG. 3B—for example, in a manner similar to the flashing of pyrolysis fluids in the method of FIG. 3A.

FIG. 19 also relates to the method of FIG. 3B and illustrates additional details of apparatus for processing pyrolysis formation fluids including hydrocarbon and aqueous formation fluids. In the non-limiting example of FIG. 19, pyrolysis gases from production wells are processed by a cooler/condenser 750 and mixed with pyrolysis liquids from the production well. This mixture is subjected to a desalting and dewatering process within desalting and dewatering unit 758 to yield a brine stream and a cold hydrocarbon-rich fluids stream. The cold hydrocarbon-rich fluids stream is heated in heat exchanger 754 and enters stripper/stabilizer 730 where (i) gases are removed to form a gas stream; and (ii) the outlet hydrocarbon stream is stabilized (i.e. lower in volatility and, for example, pipelinable under standard operating conditions), Furthermore, due to contact with hot steam, the outlet hydrocarbon stream is hotter than the input stabilizer feed. In the design of FIG. 19, it is possible to recover at least some of the enthalpy of the steam (i.e. employed within stripper/stabilizer 7320) in heat exchanger 754.

The colder stabilized hydrocarbon-rich fluids stream enters two phase separator 762 where water is separated therefrom. The stabilized unhydrotreated synthetic condensate (SUSC) exiting from two phase separator 762 may be introduced (e.g. via production well 224B) into pore space of the previously-pyrolyzed storage area 710 (see step S304 of FIG. 3B).

FIG. 20 also relates to the embodiment of FIG. 3B. In some embodiments, the SUSC stored may be primarily a specific fraction MW or boiling point rather than a broader variety of hydrocarbons of different molecular weights. In the example of FIG. 20, pyrolysis-derived hydrocarbon fluids (i.e. unhydrotreated) are received into a desalting and dewatering unit 758 configured to separate hydrocarbon fluids from aqueous brine. The hydrocarbon fluids from the desalting and dewatering unit 758 are received into atmospheric distillation unit 770. Various hydrocarbon fluid fractions are received from the distillation unit (see FIG. 20).

Since each fraction has different phase properties (e.g. different boiling points, etc), it may be advantageous to store each fraction in a different previously-pyrolyzed oil shale storage area 770 where the storage areas are non-communicating with each other. For each respective storage area, the respective SUSC therein are maintained at a temperature above their respective one atmospheric boiling point (i.e. of the respective SUSC) but at a pressure sufficient so that SUSC is stored in the storage area substantially at or above bubble point conditions. In this manner, it is possible to benefit from the combination of liquid-phase storage (i.e. for storage efficiency) and gas-phase recovery (i.e. for rapid access to stored hydrocarbon fluids).

The present invention has been described using detailed descriptions of embodiments thereof that are provided by way of example and are not intended to limit the scope of the invention. The described embodiments comprise different features, not all of which are required in all embodiments of the invention. Some embodiments of the present invention utilize only some of the features or possible combinations of the features. Variations of embodiments of the present invention that are described and embodiments of the present invention comprising different combinations of features noted in the described embodiments will occur to persons skilled in the art. 

What is claimed is:
 1. A hydrocarbon strategic reserve method comprising: operating production wells deployed in a post-pyrolysis oil shale formation at significantly elevated wellhead pressures for an extended period of time so as to store hot hydrocarbon fluids within pore space thereof, the hydrocarbon fluids being stored (i) at a depth of at least 100 meters or at least 200 meters or at least 300 meters and/or (ii) substantially at or above bubble point curve of the hydrocarbon fluids.
 2. The method of any preceding claim wherein the stored hydrocarbon fluids include and/or are primarily unhydrotreated fluids.
 3. The method of any preceding claim wherein the stored hydrocarbon fluids are primarily C7+ hydrocarbon fluids.
 4. The method of any preceding claim wherein the stored hydrocarbon fluids are primarily native C7+ pyrolysis fluids derived from the oil shale formation and stored in situ therein.
 5. The method of any preceding claim wherein the stored hydrocarbon fluids comprise a stabilized unhydrotreated synthetic condensate (SUCS) derived from pyrolysis fluids.
 6. The method of any preceding claim wherein the stored hydrocarbon fluids include external hydrocarbon fluids that are injected into pore space of the post-pyrolysis oil shale formation after pyrolysis thereof.
 7. The method of any preceding claim wherein the external hydrocarbon fluids include methane.
 8. The method of any preceding claim wherein the stored hydrocarbon fluids are native C7+ pyrolysis fluids derived from the oil shale formation and stored in situ therein, wherein the production wells are dual phase production wells, and wherein the method further comprises: upon pyroylsis of the oil shale formation, operating the production wells therein at the significantly elevated wellhead pressure so that primarily aqueous pyrolysis liquids are recovered by pumping through production tubulars of the production wells while pyrolysis gases are recovered via an annular section of the production wells.
 9. The method of any preceding claim wherein the production wells are operated for the extended period of time at a governing wellhead pressure of at least 20 atmospheres, or at least 30 atmospheres, or at least 40 atmospheres, or at least 50 atmospheres, or at least 60 atmospheres.
 10. The method of any preceding claim wherein the hot hydrocarbon fluids are stored at a depth of at least 100 meters, or at least 300 meters, or at least 350 meters, or at least 400 meters.
 11. The method of any preceding claim wherein the hot hydrocarbon fluids are stored for the extended period of time comprise primarily C7+ hydrocarbon fluids, or primarily C8+ hydrocarbon fluids.
 12. The method of any preceding claim wherein the hot hydrocarbon fluids are stored for the extended period of time substantially at or above bubble point curve thereof.
 13. The method of any preceding claim wherein a temperature of the hot hydrocarbon fluids is at least 160 degrees, or at least 180 degrees, or at least 200 degrees, or at least 250 degrees, or at least 275 degrees, or at least 300 degrees.
 14. The method of any preceding claim wherein the target portion has a length, width, and height of at least 100 meters.
 15. The method of any preceding claim wherein the hot hydrocarbon fluids are stored for the extended period of time substantially throughout an entirety of the target portion.
 16. A method of creating a hydrocarbon strategic reserve of hydrocarbon fluids within an oil shale formation, the method comprising: operating the subsurface heaters so to pyrolyze, by an in situ thermal process, a significant portion of the oil shale formation; and operating the production wells so as to recover, in the liquid phase, a majority of the aqueous pyrolysis formation fluids of the significant portion of the oil shale formation while substantially all of the C7+ pyrolysis formation fluids of the pyrolyzed significant portion remain in the pore space thereof.
 17. The method of claim 16 wherein the majority of the aqueous pyrolysis formation fluids of the significant portion of the oil shale formation are recovered by pumping.
 18. The method of claim 16 wherein the majority of the aqueous pyrolysis formation fluids of the significant portion of the oil shale formation are recovered by pumping through a production tubular of a dual-phase production well.
 19. The method of any of claims 16-18 wherein a downhole separator is maintained at or near the production well.
 20. The method of any of claims 16-19 wherein a cold sump is maintained at or near the production well.
 21. A method of creating and maintaining a hydrocarbon strategic reserve, the method comprising: a. during a pyrolysis phase, operating subsurface heaters so as to pyrolyze, by an in situ thermal process, a target portion of an oil shale formation having a depth of at least 100 meters or at least 200 meters or at least 300 meters, thereby converting organic matter therein into hot pyrolysis fluids; and b. during a storage phase and after a majority of the organic matter has been converted into hot pyrolysis fluids, storing a majority of the hot pyrolysis fluids within the pore space of the target portion for an extended period of time, wherein during substantial entireties of each of the pyrolysis and storage phases, the target portion is maintained at a wellhead pressure of at least 20 atmospheres, or at least 30 atmospheres, or at least 40 atmospheres, or at least 50 atmospheres, or at least 60 atmospheres.
 22. A method of creating and maintaining a hydrocarbon strategic reserve within an oil shale formation, the method comprising: a. pyrolyzing organic matter of a first oil shale target region into pyrolysis fluids b. producing the pyrolysis fluids via multi-phase production wells; c. forming a stabilized unhydrotreated synthetic condensate (SUSC) from the produced pyrolysis fluids by separating therefrom (i) water, (ii) light hydrocarbon fractions and (iii) light sulfur-containing molecules; d. introducing the hydrocarbon fluid comprising or derived from the SUSC into a second oil shale target region that is hot, previously pyrolyzed and non-communicating with the first oil shale target region so that the introduced hydrocarbon fluid resides within pore space of the second oil shale target region; and e. operating production wells within the second oil shale target region at an elevated pressure so as to store the introduced hydrocarbon fluid for an extended period of time as a hot fluid and substantially at or above its bubble point curve.
 23. The method or system of any previous claim wherein the wellhead pressure is maintained (i) at or above 30 atmospheres during substantial entireties of the pyrolyzing and the storing; or (ii) at or above 40 atmospheres during substantial entireties of the pyrolyzing and the storing; or (iii) at or above 50 atmospheres during substantial entireties of the pyrolyzing and the storing; or (iv) at or above 60 atmospheres during substantial entireties of the pyrolyzing and the storing.
 24. The method or system of any previous claim wherein a depth of the target portion is at least 200 meters or at least 300 meters, or at least 350 meters, or at least 400 meters.
 25. The method or system of any preceding claim wherein a molar majority of the hot hydrocarbon pyrolysis fluids stored for the extended period of time are C7+ pyrolysis fluids.
 26. The method or system of any preceding claim wherein a temperature of the extended-period-stored hot hydrocarbon pyrolysis fluids equals or exceeds 250 degrees Celsius.
 27. The method or system of any preceding claim wherein a significant fraction of the organic matter of the target portion is pyrolyzed into the hydrocarbon pyrolysis fluids which are stored within the target portion for the extended period of time.
 28. The method or system of any preceding claim wherein a majority, by mass, of the organic matter of the target portion is pyrolyzed into the hydrocarbon pyrolysis fluids which are stored within the target portion for extended period of time.
 29. The method of any preceding claim wherein the target portion has a length, width, and height of at least 50 meters, or at least 100 meters.
 30. The method or system of any preceding claim wherein the formed hydrocarbon pyrolysis fluids are stored for the extended period of time substantially throughout an entirety of the target portion.
 31. The method or system of any preceding claim wherein a majority of the stored hydrocarbon pyrolysis fluids remain within the target portion at the depth of at least 250 meters during entireties of the pyrolyzing, the storing and in the interim.
 32. The method or system of any preceding claim wherein substantially all of the stored hydrocarbon pyrolysis fluids remain within the target portion at the depth of at least 250 meters during entireties of the pyrolyzing, the storing and in the interim.
 33. A method of creating and maintaining a hydrocarbon strategic reserve within an oil shale formation, the method comprising: a. pyrolyzing organic matter of first oil shale target region into pyrolysis fluids comprising steam and vapor-phase hydrocarbons; b. producing the pyrolysis fluids via production wells; c. cooling and separating the pyrolysis fluids into hydrocarbon and aqueous condensates; and d. introducing a hydrocarbon fluid comprising the hydrocarbon condensate or a hydrocarbon derivative thereof into a hot second oil shale target region that is pre-pyrolyzed and significantly horizontally displaced from the first oil shale target region so that the introduced hydrocarbon fluid resides within pore space of the second oil shale target region at a depth of at least 100 meters or at least 200 meters or at least 300 meters.
 34. The method or system of any of preceding claim wherein the introduced hydrocarbon fluid is heated by latent heat of the pre-pyrolyzed second oil shale target region to at least 250 degrees.
 35. The method or system of any preceding claim further comprising storing the introduced hydrocarbon fluid within pore space of the second oil shale target region at the depth of at least 250 meters for an extended period of time.
 36. The method or system of any preceding claim wherein the introduced hydrocarbon fluid is heated by latent heat of the pre-pyrolyzed second oil shale target region to at least 250 degrees.
 37. The method or system of any previous claim wherein the introduced hydrocarbon fluids is stored for the extended period of time in the pore space of the second oil shale target region substantially at or above bubble point curve conditions.
 38. The method or system of any preceding claim wherein during storage, the hot hydrocarbon fluids within the pore space of the post-pyrolysis formation, have a viscosity of at most 1 cP, or at most 0.5 cP.
 39. The method or system of any preceding claim wherein a length, width and height of the target portion is at least 50 meters, and the hot hydrocarbon fluids are stored throughout substantially an entirety of the target portion.
 40. The method or system of any preceding claim wherein during substantially an entirety of the storage phase, throughout substantially an entirety of the target portion, the hot C7+ pyrolysis fluids are stably stored primarily as a liquid.
 41. The method or system of any preceding claim wherein after pyrolysis the target portion has a pyrolyzed porosity of at least 30%, or at least 40% or at least 45% or at least 50%. 